=r - psc.state.fl.us

Susan D. Ritenour Secretary and Treasurer and Regulatory Manager

One Energy Place Pensacola, Florida 32520-(1781

Tel850.444.6231 Fax 850.444.6026 [email protected]

POWER A SOUTHERN COMPANY

March 31,2009

Ms. Ann Cole, Commission Clerk Florida Public Service Commission 2540 Shumard Oak Boulevard Tallahassee FL 32399-0870

- =r c ?? d

w

Dear Ms. Cole:

Enclosed are an original and twenty-five copies of Gulf Power Company's 2009 Ten Year Site Plan, and it is filed pursuant to Rule No. 25-22.071.

Sincerely,

mv

Enclosures

cc: Beggs & Lane Jeffrey A. Stone, Esq.

TEN YEAR SITE PLAN 20019-201 8

FOR ELECTRIC GENERATING FACILITIES AND

ASSOCIATED TRANSMISSION LINES

APRIL 2009

A SOUTHERN COMPANY

GULF POWER COMPANY TEN YEAIR SITE PLAN

FOR ELECTRIC GENERATING FACILITIES AND

ASSOCIATED TRANSMISSION LINES

Submitted To The State of Florida

Public Service Commission

APRIIL I, 2009

TABLE OF CONTENTS

EXECUTIVE SUMMARY

CHAPTER I DESCRIPTION OF EXISTING FACILITIES

Description of Existing Facilities

Existing Generating Facilities

System Map

Schedule 1

CHAPTER II FORECAST OF ELECTRIC POWER DEMAND AND ENERGY CONISUMPTION

Schedule 2.1

Schedule 2.2

Forecasting Documentation

Overview

Assu m ption s I.

II.

Ill.

IV.

V.

VI.

VII.

Customer Forecast

Energy Sales IForecast

Peak Demand Forecast

Data Sources

Conservation Programs

Small Power F'roduction/ Renewable Eniergy

History and Forecast of Energy Consumption and Number of Customers by Customer Class


Page

1

10

11

14

16

19

22

22

44

46

47

I

Page

Schedule 2.3

Schedule 3.1

Schedule 3.2

Schedule 3.3

Schedule 4

Schedule 5

Schedule 6.1

Schedule 6.2

Schedule 6.3


History and Forecast of Summer Peak Demand

History and Forecast of Winter Peak Demand

History and Forecast of Annual Net Energy for Load

Previous Year Actual and Two-Year Forecast of Peak Demand and Net Energy for Load by Month

Fuel Requirements

Energy Sources - GWH

Energy Sources - YO of NEL

Renewable Energy Sources

CHAPTER 111 PLANNING ASSUMPTIONS AND PROCESSES

Integrated Resource Planning Process

Transmission Planning Process

Fuel Price Forecast Process

Southern (SES) Generic Fuel Forecast

Coal Price Forecast

Natural Gas Price Forecast

Natural Gas Availability

Strategic Issues

Environmental Concerns

48

49

50

51

52

53

54

55

56

57

61

63

64

65

67

68

70

73

I1

Availability of System Interchange

Off-System Sales

CHAPTER IV FORECAST OF FACILITIES REQUIREMENTS

Schedule 7.1

Schedule 7.2

Schedule 8

Schedule 9

Schedule 10

Capacity Resource Alternatives

Preferred and Potential Sites for Capacity Additions

Forecast of Capacity, Demand, and Scheduled Maintenance at Time Of Summer Peak

Forecast of Capacity, Demand, and Scheduled Maintenance at Time Of Winter Peal(

Planned and Prospective Generating Facility Additions and Changes

Status Report and Specifications of Proposed Generating Facilities

Status Report and Specifications of Directly associated Transmission Lines

Paqe

79

79

80

83

90

91

92

94

95

I11

This page is intentionally blank.

GULF POWER COMPANY

TEN-YEAR SITE PLAN

Executive Sum maw

The Gulf Power Company 2009 Ten-Year Site Plan is filed with the Florida

Public Service Commission (FPSC) in accordance with the requirements of

Chapter 186.801, Florida Statutes, as revised by the Legislature in 1995. The

revision replaced the Florida Department of Community Affairs with the FPSC as

the state agency responsible for the oversight of the Ten-Year Site Plan (TYSP).

The 2009 TYSP for Gulf Power Company (Gulf) is being filed in compliance with

the applicable FPSC rules.

Gulf‘s 2009 TYSP contains the documentation of assumptions used for

the load forecast, fuel forecasts, the planning processes, existing resources, and

future capacity needs and resources. The resource planning process utilized by

Gulf to determine its future capacity needs is coordinated within the Southern

electric system Integrated Resource Planning (IRP) process. Gulf participates in

the IRP process along with other Southern electric system retail operating

companies, Alabama Power Company, Georgia Power Company, and

Mississippi Power Company, (collectively, the “Southern electric system” or

SES), and it shares in a number of benefits gained from planning in conjunction

with a large system such as the SES. These benefits include the economic

sharing of SES generating reserves, the ability to install large, efficient

generating units, and reduced requirements for operating reserves.

1

The capacity resource needs set forth in the SES IRP are driven by the

demand forecast that includes the load reduction effects of projected demand-

side measures that are embedded into the forecast prior to entering the

generation mix process. The generation mix process uses PROVIEW@ to

screen the available technologies in order to produce a listing of preferred

capacity resources from which to select the most cost-effective plan for the

system. The resulting SES resource needs are then allocated among the

operating companies based on reserve requirements, and each company then

determines the resources that will best meet its capacity and reliability needs.

During the 2009 TYSP cycle, Gulf has two purchased power agreements

(PPAs) that will supply 488 megawatts (MW) of peaking power from two existing

regional market facilities to serve Gulf customers’ electrical needs from June 1,

2009 until May 31,2014. These PPAs were approved by the FPSC in Order No.

PSC-07-0329-PAA-El dated April 16, 2007. With this PPA capacity shown as

committed capacity through May 2014, Gulfs additional resource needs for this

planning cycle increase annually to 976 MW by the summer of 2014 and

continue to grow to 1344 MW by 2018. Therefore, Gulf will need to add

significant generation resources in 2014 due to the expiration of the two PPAs

totaling 488 MW and an increase in expected summer peak demands in years

201 1 through 201 8 of the 2009 TYSP cycle.

In order to meet its future capacity needs, Gulf has continued to evaluate

the construction of generating facilities or the acquisition of equivalent capacity

resources in coordination with other SES operating companies. In late 2008,

Gulf was selected through an RFP process to construct, own and operate a

2

3 MW landfill gas to energy facility ai, the Escambia County, Florida landfill. Gulf

will petition the FPSC for cost recovery approval of this project in 2009, and the

facility could be on-line as early as April 2010. Gulf has also initiated detailed

studies to convert its 92 MW Scholz coal-fired facility in Jackson County, Florida

to a biomass facility following its retirement in December 201 1. Gulf is projecting

this facility to be on-line by June 2013. Both of these proposed renewable

projects have been included in Gulf's 2009 TYSP.

Gulf's 2008 TYSP generation expansion plan called for the addition of an

840 MW gas-fired combined cycle unit in Northwest Florida in 2014. Gulf began

preparation of an RFP in early 2008 to determine the most cost-effective

resource(s) to meet its projected need in 2014. Just prior to issuing the RFP in

late 2008, Gulf became aware of a non-affiliated power marketer's desire to

negotiate a PPA for the output of an1 existing 885 MW gas-fired combined cycle

generating unit interconnected with the SES. Gulf postponed the issuance of the

Gulf RFP and began negotiating a PPA with this non-affiliated party. Gulf signed

the PPA on March 16, 2009. The term of this 885 MW PPA begins on the later of

June 2009 or on such date that the FPSC issues a final, non-appealable order for

cost recovery and ends May 24, ;!023. When combined with the proposed

capacity additions of the other Southern electric system operating companies,

Gulf's proposed capacity additions via the new 885 MW PPA and the above

mentioned renewable projects will result in an SES planning reserve margin of

approximately 15% through 2018.

3

This 885 MW PPA is contingent upon receipt of a final, non-appealable

order from the FPSC for recovery of costs associated with the PPA. In the event

the PPA is not approved, Gulf will proceed with its plan to construct an 840 MW

combined cycle unit in Northwest Florida by issuing an RFP as soon as practical.

Studies to determine the latest cost and best location for this potential combined

cycle generating facility will have to be refreshed to include new economic factors

and the latest regulatory requirements, but the location of this self build project

has been narrowed to two primary sites at Gulfs existing generating facility sites

in Northwest Florida. Schedule 9 of this TYSP document contains more detailed

information on this potential combined cycle addition.

4

CHAPTER I

DESCRIPTION OF EXISTING FACILITIES

DESCRIPTION 0 f: EXIST1 NG FACl LIT1 ES

Gulf owns and operates generating facilities at four sites in Northwest

Florida (Plants Crist, Smith, Scholz, and Pea Ridge). Gulf also owns a 50%

undivided ownership interest in Unit 1 and Unit 2 at Mississippi Power

Company’s Daniel Electric Generating Facility. Gulf has a 25% ownership in Unit

3 at Georgia Power Company’s Scherer Electric Generating Facility which is

completely dedicated to wholesale unit power sale contracts. This fleet of

generating units consists of eleven fossil steam units, one combined cycle unit,

and four combustion turbines. Schedule 1 shows 930 MW of steam generation

located at the Crist Electric Generating Facility near Pensacola, Florida. The

Lansing Smith Electric Generating Facility near Panama City, Florida, includes

357 MW of steam generation, 556 MW (summer rating) of combined cycle

generation, and 32 MW (summer rating) of combustion turbine facilities. The

Scholz Electric Generating Facility, near Sneads, Florida, consists of 92 MW of

steam generation. Gulf‘s Pea Ridge Facility, in Pace, Florida, consists of three

combustion turbines associated with an existing customer’s cogeneration facility,

which adds 12 MW (summer rating) to Gulf‘s existing capacity.

Including Gulf‘s ownership interest in the Daniel fossil steam Units 1 and 2

and the Scherer fossil steam Unit 3, Gulf has a total net summer generating

capability of 2,711 MW and a total net winter generating capability of 2,750 MW.

The existing Gulf system in Northwest Florida, including generating plants,

substations, transmission lines and service area, is shown on the system map on

5

of this TYSP.

presented on Schedule 1 of this TYSP.

Data regarding Gulf's existing generating facilities is

6

(1)

Plant Name

Crist

Lansing Smith

Scholz

(A) Daniel

(A) Scherer

Pea Ridge

Unit No. Location -

Escambia County 2511 N130W

4 5 6 7

Bay County 36/2S/1 5W

1 2 3 A

Jackson County 12/3N/7W

1 L

Jackson County, MS 42/5S/6W

1 L

3 Monroe County, GA

Santa Rosa County 15/1N/29W

1 2 3

(4)

Unit Type

FS FS FS FS

FS FS cc CT

FS FS

FS FS

FS

CT CT CT

GULF POWER COMPANY

SCHEDULE 1 EXISTING GENERATING FACILITIES

AS OF DECEMBER 31,2008

C C C C

C 2

NG LO

C C

C C

C

NG NG NG

(7) (8)

Fuel Transp Pri All - -

WA PL WA PL WA PL WA PL

WA --

PL -- TK --

.... v v n --

RR WA RR WA

RR TK RR TK

RR --

PL -- PL -- PL --

(10)

Com'l In- Service MoNr

7/59 616 1 5/70 8/73

6/65 61'67 4/02 517 1

3/53 10153

9/77 6/81

1 187

5/98 5/98 5/98

(11)

Exptd Retrmnt MoNr

12/24 12/26 12/35 12/38

12/30

12/37 12/17

l n l n n I L l J L

12/11 12/11

12/32 12/36

12/42

1211 8 12/18 12/18

(12)

Gen Max Nameplate

KW

1,135.250

93,750 93,750

369,750 578,000

1,001,500

149,600

619,650 41,850

Inn 1 n m IYU..tUU

98.ooo

49,000 49,000

548,250

274,125 274,125

222,750

14,250

4,750 4,750 4,750

Total Svstem

Page i of2

Net Capability Summer Winter

MW MW

930.0 930.0

78.0 78.0 78.0 78.0

302.0 302.0 472.0 472.0

945.0 981.0

162.0 162.0

556.0 584.0 32.0 40.0

- -

- -

- -

.ncn * n c n 1 Y J . U 1 Y J . U

- 92.0 92.0

46.0 46.0 46.0 46.0

- - 513.0 513.0

260.0 260.0 253.0 253.0

219.0 219.0

12.0 15.0

4.0 5.0 4.0 5.0 4.0 5.0

- -

2,711 .O 2,750.0

SCHEDULE 1

Abbreviations:

Fuel

FS - Fossil Steam CT - Combustion Turbine CC - Combined Cycle NG - Natural Gas C - Coal LO - Light Oil HO - Heavy Oil

Fuel Transportation

PL - Pipeline WA - Water TK - Truck RR - Railroad

Page 2 of 2

NOTE: (A) Unit capabilities shown represent Gulfs portion of Daniel Units 1 & 2 (50%) and Scherer Unit 3 (25%).

CHAPTER II

FORECAST OF ELECTRIC POWER DEMAND AND ENERGY CONSUMPTION

GULF POVU'ER COMPANY

LOAD FORECASTING METHODOLOGY

OVERVIEW

Gulf views the forecasting effort as a dynamic process requiring ongoing efforts

to yield results which allow informed planning and decision-making. The total

forecast is an integration of different techniques and methodologies, each applied to

the task for which it is best suited. Many of the techniques take advantage of the

extensive data made available through ,the Company's marketing efforts, which are

predicated on the philosophy of knowing and understanding the needs, perceptions

and motivations of our customers and actively promoting wise and efficient uses of

energy which satisfy customer needs. Gulf has been a pacesetter in the energy

efficiency market since the development and implementation of the Goodcents

Home program in the mid-70's. Thiis program brought customer awareness,

understanding and expectations regarding energy efficient construction standards in

Northwest Florida to levels unmatched elsewhere. Since that time, the Goodcents

Home program has seen many enhanclements, and has been widely accepted not

only by our customers, but by builders, contractors, consumers, and other electric

utilities throughout the nation, providing clear evidence that selling efficiency to

customers can be done successfully.

The Marketing Services section of Gulf's Marketing Department is responsible

for preparing forecasts of customers, energy and peak demand. A description of the

assumptions and methods used in the development of these forecasts follows.

10

I. ASSUMPTIONS

A. ECONOMIC OUTLOOK

In the months since Gulf Power produced its 2009 Budget, the national

economy was declared to be in a recession which started in December 2007. The

March 2008 economic forecast from Moody’s Economy.com, whose economics drive

the Gulf Power 2009 Budget, describes the national economy as contracting and on

its way to recession but not actually in recession. For the State of Florida, that

forecast describes the economy to be extremely weak. A primary cause for this

slowdown is the depressed housing market which was particularly severe in Florida.

The 2009 Budget forecast assumes that during 2008 real GDP growth will

slow to 1.5% but will grow by 3.5% for both 2009 and 2010 before decelerating to

2.8% in 201 1.

The March 2008 Moody’s Economy.com economic forecast predicted weak

conditions based on falling business and consumer confidence, the housing crisis, a

global financial lockdown, and high oil prices. The drop in both consumer and

business confidence is based on lost faith in a thriving economy starting in the

Summer of 2007 with the sub-prime financial crisis. Falling consumer confidence has

resulted in sluggish consumption spending. The housing crisis resulted in declining

home sales, house prices, and housing starts. Foreclosures continued to mount

signaling that the housing slump would continue. Normal credit flows in the domestic

and global financial system continued to deteriorate from rising mortgage defaults

and a flood of undervalued mortgage-backed securities. As a result, credit spreads

widened signaling the unwillingness of banks to lend. High energy prices in March

11

2008 continued to plague the economy as oil rose above $100 per barrel with higher

predictions over the summer. The high energy cost burden on consumers threatened

to erase any spending stimulus hoped for with the recent income tax rebates.

The resulting short-term outlook in the March 2008 forecast called for the

economy to struggle until the housing and mortgage markets find their footing.

Federal policies of monetary easing and increased fiscal stimulus were expected to

end a two-quarter stretch of mildly negative economic growth by mid-year, but more

fiscal stimulus would be needed to keep the recovery self-sustaining.

Over the long-run, real GDP is forlecasted to grow slightly faster while total

employment will be slightly slower compared to the 2008 Budget. These changes

were the result of studies showing slower inflation and lower labor force participation

rates. The long-term results, however, generally match last year's outlook. Real

GDP growth over the full 25 years of the forecast is predicted to rise from a 2.4%

compound annual rate in the 2008 Budget to 2.5% in the 2009 Budget. Total

employment over the 25-year long-term was forecast to grow 1.1 % in the 2008

Budget but slow to 0.7% in the 2009 Buclget. Real personal income growth remained

at 2.3% in both the 2007 Budget and 2008 Budget.

B. TERRITORIAL ECONOMIC OUTLOOK

Gulf's projections reflect the economic outlook for our service area as provided

by Moody's Economy.com, a renowned economic service provider. Gulf's forecast

assumes that service area population growth will continue to exceed the nation's

growth and slightly exceed the rate of growth for the state of Florida. Gulf's

projections incorporate electric price assumptions derived from the 2008 Gulf Power

12

Official Long-Range Forecast. Fuel price projections for gas and oil are developed

by Southern Company Services (SCS) Fuel Procurement staff with input from outside

consultants. The following tables provide a summary of the assumptions associated

with Gulf's forecast:

TABLE I

ECONOMIC SUMMARY (2007-201 3)

GDP Growth 2.2 YO - 2.7 %

Interest Rate 4.8 Yo - 5.9 % (30 Year AAA Bonds)

Inflation 2.7 % - 1.8 %

TABLE 2

AREA DEMOGRAPHIC SUMMARY (2007-201 3)

Population Gain

Net Migration

Average Annual Population Growth

Average Annual Labor Force Growth

80,352

37,202

1.4 %

1.4 Yo

13

II. CUSTOMER FORECAST

A. RESIDENTIAL CUSTOMER FORECAST

The immediate short-term forecast (0-2 years) of customers is based

primarily on projections prepared by district personnel. Gulf district personnel

remain abreast of local market and economic conditions within their service

areas through direct contact with economic development agencies, developers,

builders, lending institutions and other key contacts. The projections prepared

by the districts are based upon reicent historical trends in customer gains and

their knowledge of locally planned construction projects from which they are

able to estimate the near-term anticipated customer gains. These projections

are then analyzed for consistency, and the incorporation of major construction

projects and business developments is reviewed for completeness and

accuracy. The end result is a near-term forecast of residential customers.

For the remaining forecast horizon (3-25 years), the Gulf Economic

Model, a competition-based econometric model developed by Moody’s

Economy.com, is used in the development of residential customer projections.

Projections of births, deaths, and population by age groups are determined by

past and projected trends. Migration is determined by economic growth relative

to surrounding areas.

The forecast of residential customers is an outcome of the final section

of the migration/demographic element of the model. The number of residential

customers Gulf expects to serve is calculated by multiplying the total number of

households located in the eight counties in which Gulf provides service by the

14

B.

percentage of customers in these eight counties for which Gulf currently

provides service.

The number of households referred to above is computed by applying a

household formation trend to the previously mentioned population by age group,

and then by summing the number of households in each of five adult age

categories. As indicated, there is a relationship between households, or

residential customers, and the age structure of the population of the area, as

well as household formation trends. The household formation trend is the

product of initial year household formation rates in the Gulf service area and

projected U.S. trends in household formation.

COMMERCIAL CUSTOMER FORECAST

The immediate short-term forecast (0-2 years) of commercial

customers, as in the residential sector, is prepared by the district personnel in

similar fashion utilizing recent historical customer gains information and their

knowledge of the local area economies and upcoming construction projects. A

review of the assumptions, techniques and results for each district is

undertaken, with special attention given to the incorporation of major

commercial development projects.

Beyond the immediate short-term period, commercial customers are

forecast as a function of residential customers, reflecting the growth of

commercial services to meet the needs of new residents. Implicit in the

commercial customer forecast is the relationship between growth in total real

disposable income and growth in the commercial sector.

15

111. ENERGY SALES FORECAST

A. RESIDENTIAL SALES FORECAST

The residential energy sales forecast is developed utilizing multiple

regression analyses. Monthly class energy use per customer per billing day is

estimated based upon recent historical data, expected normal weather and

projected price. The model output is then multiplied by the projected number of

customers and billing days by month to expand to the total residential class.

The residential sales forecast reflects the continued impacts of Gulfs

GoodCents Home program and efficiency improvements undertaken by

customers as a result of the GoodCents Energy Survey program, as well as

conversions to higher efficient outdoor lighting. The residential sales forecast

also reflects the anticipated incremental impacts of Gulf's Demand-Side

Management (DSM) Plan, approved in March 2005, designed to meet the

Commission-approved demand and energy reduction goals established in

September 2004. Additional information on the residential conservation

programs and program features are provided in the Conservation Programs

section of this document.

B. COMMERCIAL SALES FORECAST

The commercial energy sales forecast is also developed utilizing

multiple regression analyses. Monthly class energy use per customer per billing

day is estimated based upon recent historical data, expected normal weather

16

and projected price. The model output is then multiplied by the projected

number of customers and billing days by month to expand to the total

commercial class.

The commercial sales forecast reflects the continued impacts of Gulfs

Commercial Goodcents building program and efficiency improvements

undertaken by customers as a result of Commercial Energy Audits and

Technical Assistance Audits, as well as conversions to higher efficient outdoor

lighting. The commercial sales forecast also reflects the anticipated incremental

impacts of Gulf's DSM Plan, approved in March 2005, designed to meet the

Commission-approved demand and energy reduction goals established in

September 2004. Additional information on the Commercial Conservation

programs and program features are provided in the Conservation Proqrams

section of this document.

C. INDUSTRIAL SALES FORECAST

The short-term industrial energy sales forecast is developed using a

combination of on-site surveys of major industrial customers, trending

techniques, and multiple regression analyses. Gulf's largest industrial

customers are interviewed to identify load changes due to equipment addition,

replacement or changes in operating characteristics.

The short-term forecast of monthly sales to these major industrial

customers is a synthesis of the detailed survey information and historical

monthly load factor trends. The forecast of short-term sales to the remaining

17

smaller industrial customers is developed using a combination of trending

techniques and multiple regression analyses.

The long-term forecast of industrial energy sales is based on

econometric models of the chemical, pulp and paper, other manufacturing, and

non-manufacturing sectors. The industrial sales forecast also reflects the

anticipated incremental impacts of Gulf's DSM Plan, approved in March 2005,

designed to meet the Commission-approved demand and energy reduction

goals established in September 2004. Additional information on the

conservation programs and program features are provided in the Conservation

Programs section of this document.

D. STREET LIGHTING SALES FORECAST

The forecast of monthly (energy sales to street lighting customers is

based on projections of the number of fixtures in service, for each of the

available fixture types.

The projected number of fixtures by fixture type is developed from

analyses of recent historical fixture data to discern the patterns of fixture

additions and deletions. The estimated monthly kilowatt-hour consumption for

each fixture type is multiplied by the projected number of fixtures in service to

produce total monthly sales for a given type of fixture. This methodology allows

Gulf to explicitly evaluate the impacts of lighting programs, such as mercury

vapor to high pressure sodium conversions.

18

E. WHOLESALE ENERGY FORECAST

The forecast of energy sales to wholesale customers is developed

utilizing multiple regression analyses. Monthly energy purchases per day for

each of Gulf's wholesale customers are estimated based upon recent historical

data and expected normal weather. The model output is then multiplied by the

projected number of days by month to expand to the customer totals, which are

then summed to develop the class totals.

F. COMPANY USE & INTERDEPARTMENTAL ENERGY

The annual forecast for Company energy usage was based on recent

historical values, with appropriate adjustments to reflect short-term increases in

energy requirements for anticipated new Company facilities. The monthly

spreads were derived using historical relationships between monthly and annual

energy usage.

IV. PEAK DEMAND FORECAST

The peak demand forecast is prepared using the Hourly Electric Load

Model (HELM), developed by ICF, Incorporated, for EPRl under Project

RPI 955-1. The resulting output from the model is hourly electrical loads over

the forecast horizon.

The summer and winter peak demands are the maximum of the hourly

forecasted loads in July and January, respectively. Gulf's summer peak

demand typically occurs in the month of July, while Gulf's winter peak demand

typically occurs in the month of January.

19

Load shape forecasts halve always provided an important input to

traditional system planning functions. Forecasts of the pattern of demand have

acquired an added importance due to structural changes in the demand for

electricity and increased utility involvement in influencing load patterns for the

mutual benefit of the utility and its customers.

HELM represents an approach designed to better capture changes in

the underlying structure of electriciity consumption. Rapid increases in energy

prices during the 1970's and early 1980's brought about changes in the

efficiency of en erg y-usi ng eq u i p nnen t . Add it ional I y , sociode mog rap h ic and

microeconomic developments have changed the composition of electricity

consumption, including changes in fuel share, housing mix, household age and

size, construction features, mix of commercial services, and mix of industrial

products.

In addition to these naturally occurring structural changes, utilities have

become increasingly active in offering customers options which result in

modified consumption patterns. An important input to the design of such

demand-side programs is an assessment of their likely impact on utility system

loads.

HELM has been designed to forecast electric utility load shapes and to

analyze the impacts of factors such as alternative weather conditions, customer

mix changes, fuel share changes, and demand-side programs. The structural

detail of HELM provides forecasts of hourly class and system load curves by

weighting and aggregating load shalpes for individual rate level components.

20

Model inputs include rate level energy forecasts consistent with the cost

of service (COS) load shape data collected from COS load research samples as

well as individual customer load data for many of the larger customers. Inputs

are also required to reflect new technologies, rate structures and other demand-

side programs. Model outputs include hourly system and class load curves,

load duration curves, monthly system and class peaks, load factors and energy

requirements by season and rating period.

The methodology embedded in HELM may be referred to as a "bottom-

up" approach. Class and system load shapes are calculated by aggregating the

load shapes of component rates and individual large customer load shapes.

The system demand for electricity in hour i is modeled as the sum of demands

by each end-use in hour i:

Where: Li = system demand for electricity in hour i;

NR = number of residential rate class loads;

NC = number of commercial rate class loads;

NI = number of industrial rate class loads;

LR,i = demand for electricity by residential rate R in hour i;

Lc,i = demand for electricity by commercial rate C in hour i;

Ll,i = demand for electricity by industrial ratekustomer I in hour i;

Misci = other demands (wholesale, street lighting, losses, company

use) in hour i.

21

V. DATA SOURCES

Gulf utilizes Company historical customer, energy and revenue data by

rate and class, and historical hourly load data coupled with weather information

from Weather Data Viewer (WDV) and The National Oceanic and Atmospheric

Administration (NOAA) to drive the energy and demand models. Individual

customer historical data is utilized in developing the projections for Gulfs largest

commercial and industrial customers.

Gulf‘s models also utilize economic projections provided by Moody’s

Economy.com, a renowned economic services provider. Moody’s

Economy.com utilizes the Bureau of Labor Statistics for data on employment,

unemployment rate and labor force. Personal Income data is obtained from the

Bureau of Economic Analyses. Population and Population by Age Cohort,

Households and Housing Permit information is obtained from the U.S. Bureau of

Census.

VI. CONSERVATION PROGRAMS

As previously mentioned, Gulfs forecast of energy sales and peak

demand reflect the continued impacts of our conservation programs. The

following provides a listing of the current conservation programs and program

features with estimates of reductions in peak demand and net energy for load

reflected in the forecast as a result of these programs. These reductions also

reflect the anticipated impacts of these programs as submitted in Gulfs DSM

22

Plan filed December 1, 2004, modified on January 26, 2005 (Docket No.

040032-EG) and approved by the FPSC in Order No. PSC-05-0273-PAA-EG

issued March 14, 2005. By Order No. PSC-07-0455-PAA-EG issued on May

29, 2007, in Docket No. 070119-EG, the Commission approved minor

modifications to Gulf's Commercial and Residential Geothermal Heat Pump

Programs. In December 2008, the Commission approved two new pilot

programs in Order No. PSC-08-0802-PAA-EG for increased educational

emphasis of conservation and introduction of demand-side renewables in the

form of solar thermal water heating. Gulf's conservation programs were

designed to meet the incremental impacts of the Commission-approved demand

and energy reduction DSM goals established in Order No. PSC-04-0764-PAA-

EG on August 9,2004.

A. RES I D ENTl AL CONSERVATION

1. Goodcents Home/Enerqy Star

In the residential sector, Gulfs Goodcents Home/Energy Star

Program is designed to make cost-effective increases in the efficiencies of

the new home construction market. This is being achieved by placing

greater requirements on cooling and water heating equipment efficiencies,

proper HVAC sizing, increased insulation levels in walls, ceilings, and

floors, and tighter restrictions on glass area and infiltration reduction

practices. In addition, Gulf monitors proper quality installation of all the

above energy features. This program also provides the opportunity to offer

23

the Energy Star Home Program to Gulf's builders and customers and

correlates the performance of Goodcents Homes to the nationally

recognized Energy Star efficiency label. In many cases, a standard

Goodcents Home will also qualify as an Energy Star home. Approximately

69,000 new homes have been constructed to Good Cents standards under

this program resulting in an annual reduction of 79 MW of summer peak

demand and annual energy savings of 203 GWh.

2. GoodCents Energy Sunrey

Gulfs Goodcents Energy Survey Program is designed to

provide existing residential customers and individuals building new homes

with energy conservation advice that encourages the implementation of

efficiency measures and options that increase comfort and reduce energy

operating costs. This program is offered as an on-site, mail-in, or on-line

survey and in all cases the customer receives whole house

recommendations. Approximately 72,000 customers have participated in

the Energy Survey Program. These participants have implemented energy

efficiency improvements estimated to result in an annual reduction of 14

MW of summer peak demand and 40 GWh annual energy savings.

3. Geothermal Heat Pump

The Residential Geothermal Heat Pump Program reduces the

demand and energy requirements of new and existing residential

customers through the promotion and installation of advanced and

24

emerging geothermal systems. Geothermal heat pumps also provide

significant benefits to participating customers in the form of reduced

operating costs and increased comfort levels, and are superior to other

available heating and cooling technologies with respect to source efficiency

and environmental impacts. Gulf's Geothermal Heat Pump Program is

designed to overcome existing market barriers, specifically, lack of

consumer awareness, knowledge and acceptance of this technology.

Additionally, the program promotes efficiency levels well above current

market conditions. Approximately 2,200 geothermal heat pumps have

been installed in Gulf's service area resulting in an annual reduction in

summer peak demand of 4 MW and annual energy savings of 5 GWh.

4. Goodcents Select

The Goodcents Select Program, an advanced energy

management program, provides Gulf's customers with a means of

conveniently and automatically controlling and monitoring their energy

purchases in response to prices that vary during the day and by season in

relation to Gulf's cost of producing or purchasing energy. The GoodCents

Select system allows the customer to control more precisely the amount of

electricity purchased for heating, cooling, water heating, and other selected

loads and to purchase electric energy on a variable price rate, including a

critical peak price (CPP). The various components of the Goodcents

Select system installed in the customer's home, as well as the components

installed at Gulf, provide constant communication between customer and

25

utility. The combination of the GoodCents Select system and Gulf‘s

innovative variable rate concept provide consumers with the opportunity to

modify their usage of electricity in order to purchase energy at prices that

are somewhat lower to significantly lower than standard rates a majority of

the time. Further, the communication capabilities of the Goodcents Select

system allow Gulf to send a CPP signal to the customer’s premises during

extreme’peak load conditions. The signal results in a reduction attributable

to predetermined thermostat isnd relay settings chosen by the individual

participating customer. The customer’s pre-programmed instructions

regarding their desired comfort levels adjust electricity use for heating,

cooling, water heating and other appliances automatically. Therefore, the

customer’s control of their electric bill is accomplished by allowing them to

choose different comfort levels at different price levels in accordance with

their individual lifestyles. Currently, approximately 8,700 customers are

participating in this program resulting in an annual reduction of 24 MW in

summer peak demand and annual energy savings of 7 GWh.

5. Solar Thermal Water Heating (pilot)

The solar thermal water heating pilot program offers residential

customers a $1,000 rebate upon installation of a qualified solar water

heating system. Solar thermal1 water heating can reduce energy usage 50-

75% compared to conventional electric resistance water heating and also

provide summer coincident peak demand savings. This program will be

evaluated at the end of 2009 to determine customers’ acceptance of this

26

technology as well as verification of anticipated energy and demand

savings.

6. Energy Education (pilot)

The energy education program is designed to increase the

overall awareness of energy conservation opportunities across Gulf's

customer base and participation in Gulf's existing energy efficiency and

conservation programs. The program includes a broad based awareness

campaign, school-based education and teacher training, and building

contractor training on energy efficient construction practices. This program

will be evaluated at the end of 2009 to determine the impact on

conservation awareness and participation levels across Gulf's service area.

B. COMMERCIALANDUSTRIAL CONSERVATION

1. Goodcents Building

In the commercial sector, Gulfs Goodcents Building Program is

designed to make cost effective increases in efficiencies in both new and

existing commercial buildings with requirements resulting in energy

conserving investments that address the thermal efficiency of the building

envelope, interior lighting, heating and cooling equipment efficiency, and

solar glass area. Additional recommendations are made, where

applicable, on energy conserving options that include thermal storage, heat

27

recovery systems, water heating heat pumps, solar applications, energy

management systems, and high efficiency outdoor lighting. Approximately

10,500 customers under this program have achieved an annual reduction

of 105 MW in summer peak demand and annual energy savings of 211

GWh.

2. Commercial/lndustrial Energy Analyses

The Commercial/lnclustrial (C/I) Energy Analyses Program is an

interactive program that provides C/I customers assistance in identifying

energy conservation opportunities. This program is a prime tool for the

Gulf Power Company C/I IEnergy Specialist to personally introduce

customers to conservation measures including low or no-cost

improvements or new electro-technologies to replace old or inefficient

equipment. Further, this program facilitates the load factor improvement

process necessary to increase performance for both the customer and Gulf

Power Company.

The C/I Energy Anallysis Program allows the customer three

primary ways to participate. A basic Energy Analyses Audit (EAA) is

provided through either an on-site survey or a direct mail survey analysis.

Additionally, a more comprehensive analysis can be provided by

conducting a Technical Assistance Audit (TAA). Approximately 18,400

customers participating in these programs have achieved an annual

reduction of 25 MW in summer peak demand and annual energy savings of

7 GWh.

28

3. Commercial Geothermal Heat Pump

The objective of the Commercial Geothermal Heat Pump

Program is to reduce the demand and energy requirements of new and

existing Commercial/lndustriaI customers through the promotion and

installation of advanced and emerging geothermal systems. Due to the

long life of space conditioning equipment, the choices that are made over

the next decade regarding space conditioning equipment will have

important economic and environmental ramifications lasting well into the

future. Geothermal heat pumps provide significant benefits to participating

customers in the form of reduced operating costs and increased comfort

levels, and are superior to other available heating and cooling technologies

with respect to source efficiency and environmental impacts. This program

will promote efficiency levels well above current market conditions,

specifically those units with an Energy Efficiency Ratio (EER) of 13.0 or

higher.

4. Real-Time Pricing

Gulf's Real Time Pricing (RTP) program is designed to take

advantage of customer price response to achieve peak demand

reductions. Customer participation is voluntary. Due to the nature of the

pricing arrangement included in this program, there are some practical

limitations to customers' ability to participate. These limitations include the

ability to purchase energy under a pricing plan which includes price

variation and unknown future prices; the transaction costs associated with

29

receiving, evaluating, and acting on prices received on a daily basis;

customer risk management policy; and other technicaVeconomic factors.

Customers participating in this program typically exhibit approximately 50

MW of reduction in summer peak demand.

5. Enemy Services

Gulf's Energy Services Program is designed to offer advanced

energy services and energy efficient end-use equipment to meet the

individual needs of large customers. These energy services include

comprehensive audits, design, construction and financing of demand

reduction or efficiency improvement energy conservation projects. This

program has resulted in a recluction of 13 MW of summer peak demand

and 42 GWh in annual energy savings.

C. CONSERVATION RESULTS SUMMARY

The following tables provide direct estimates of the energy

savings (reductions in peak demand and net energy for load) realized by

Gulfs conservation programs. These reductions are verified through on-

going monitoring in place or1 Gulfs major conservation programs and

reflect estimates of conservation undertaken by customers as a result of

Gulfs involvement. The coinservation without Gulfs involvement has

contributed to further unquantifiable reductions in demand and net energy

30

for load. These unquantifiable additional reductions are captured in the

time series regressions in our demand and energy forecasts.

31

2007

HISTORICAL TOTAL CONSERVATION PROGRAMS CUMULATIVE ANNUAL REDUCTIONS

AT GENERATOR

SUMMER WINTER NET ENERGY PEAK PEAK FOR LOAD (KW) (KW) (KWH)

355,480 420,289 701,924,646

2008 2009 201 0 201 1 2012 201 3 2014 201 5 201 6 2017 201 8

2009 BUDGET FORECAST TOTAL CONSERVATION PROGRAMS

INCREMENTAL ANNUAL REDUCTIONS AT GE.NERATOR


2008 2009 201 0 201 1 201 2 201 3 2014 201 5 201 6 201 7 201 8

5,336 8,376 8,250 8,222 8,232 8,445 8,509 8,509 8,509 8,509 8,509

13,086 17,329 17,421 17,229 17,297 18,773 1921 9 19,219 18,983 18,983 18.983

12,264,363 1 5,122,212 15,062,897 1 4,926,869 1 4,974,776 16,020,609 16,336,808 16,336,808 16,024,801 16,024,801 16,024,801

2009 BUDGET FORECAST TOTAL CONSEFilVATlON PROGRAMS CUMULATIVE ANNUAL REDUCTIONS

AT GEiNERATOR


360,816 369,192 377,442 385,664 393,895 402,340 410,849 419,359 427,868 436,377 444,886

433,374 450,703 468,124 485,354 502,651 521,424 540,643 559,863 578,846 597,829 616,812

714,189,010 729,311,221 744,374,119 759,300,988 774,275,764 790,296,372 806,633,181 822,969,989 838,994,791 855,019,592 871,044,393

32

HISTORICAL TOTAL RESIDENTIAL CONSERVATION CUMULATIVE ANNUAL REDUCTIONS

AT GENERATOR

SUMMER WINTER NET ENERGY

PEAK (KW)

PEAK (KW)

2007 175,376 274,575 363,715,485

2009 BUDGET FORECAST TOTAL RESIDENTIAL CONSERVATION I N C RE M E NTAL ANNUAL REDUCTIONS

AT GENERATOR

2008 2009 2010 201 1 2012 2013 2014 201 5 201 6 201 7 201 8

SUMMER

PEAK (KW)

4,004 6,591 6,465 6,437 6,447 6,660 6,725 6,725 6,725 6,725 6,725

WINTER

PEAK (KW)

12,393 16,368 16,460 16,268 16,336 17,812 18,258 18,258 18,022 18,022 18,022

NET ENERGY

FOR LOAD (KWH)

8,868,415 10,731,197 10,671,882 10,535,854 10,583,761 11,629,594 11,945,793 11,945,793 11,633,786 11,633,786 11,633,786

2009 BUDGET FORECAST TOTAL RESIDENTIAL CONSERVATION CUMULATIVE ANNUAL REDUCTIONS

AT GENERATOR


2008 2009 2010 201 1 2012 201 3 2014 2015 2016 2017 2018

PEAK (KW)

179,380 185,971 192,436 198,874 205,321 21 1,981 218,706 225,430 232,155 238,879 245,604

PEAK (KW)

286,968 303,336 31 9,796 336,064 352,400 370,211 388,469 406,727 424,749 442,771 460,793

372,583,900 383,315,097 393,986,979 404,522,833 4 1 5,106,594 426,736,187 438,681,980 450,627,774 462,261,560 473,895,346 485,529,133

33

H ISTO Rl CAL TOTAL COMMERCIAL/IN'DUSTRIAL DSM PROGRAMS

CUMULATIVE ANNUAL REDUCTIONS AT GElNERATOR

SUMMER WllVTER NET ENERGY

2007 180,104 145,713 327,128,241

2009 BUDGET FORECAST TOTAL COMMERCIALANIDUSTRIAL DSM PROGRAMS

INCREMENTAL ANNUAL REDUCTIONS AT GEiNERATOR

SUMMER WllVTER NET ENERGY

2008 2009 201 0 201 1 201 2 201 3 2014 201 5 2016 2017 201 8

1,332 1,785 1,785 1,785 1,785 1,785 1,785 1,785 1,785 1,785 1,785

693 96 1 96 1 96 1 96 1 96 1 96 1 96 1 96 1 96 1 96 1

3,395,948 4,391,015 4,391,015 4,391,015 4,391,015 4,391,015 4,391,015 4,391,015 4,391,015 4,391,015 4,391,015

2009 BUDGET FORECAST TOTAL COMMERCIAL/lhlDUSTRIAL DSM PROGRAMS

CUMULATIVE ANNUAL REDUCTIONS AT GENERATOR

SUMMER WIINTER NET ENERGY

2008 2009 201 0 201 1 201 2 201 3 2014 201 5 201 6 201 7 201 8

181,436 185,971 192,436 198,874 205,321 21 1,981 21 8,706 225,430 232,155 238,879 245,604

286,968 303,336 319,796 336,064 352,400 370,211 388,469 406,727 424,749 442,771 460,793

372,583,900 383.31 5,097 393,986,979 404,522,833 415,106,594 426,736,187 438,681,980 450,627,774 462,261,560 473,895,346 485,529,133

34

H I STORl CAL TOTAL OTHER DSM PROGRAMS



2007 11,080,920

2009 BUDGET FORECAST TOTAL OTHER DSM PROGRAMS

INCREMENTAL ANNUAL REDUCTIONS AT GENERATOR


2008 2009 201 0 201 1 2012 2013 2014 2015 201 6 2017 201 8

2009 BUDGET FORECAST TOTAL OTHER DSM PROGRAMS



2008 2009 201 0 201 1 2012 201 3 2014 201 5 2016 201 7 201 8

11,080,920 1 1,080,920 11,080,920 11,080,920 11,080,920 11,080,920 11,080,920 11,080,920 11,080,920 11,080,920 11,080,920

35

HISTORICAL TOTAL EXlSTlhIG DSM PROGRAMS

CUMULATIVE ANN U AL RED U CTI 0 N S AT GEINERATOR


PEAK PEAK FORLOAD (KW) (KW) (KWH)

2007 234,989 299,964 561,046,095

2009 BUDGET FORECAST TOTAL EXlSTlhlG DSM PROGRAMS

INCREMENTAL ANNUAL REDUCTIONS AT GEiNERATOR



2008 1,127 8,385 5,673,680 2009 1,246 9,207 6,256,208 2010 1,248 9,221 6,266,575 201 1 1,220 9,030 6,130,547 2012 1,230 9,097 6,178,454 201 3 1,443 10,573 7,224,287 2014 1,507 11,020 7,540,486 2015 1,507 11,020 7,540,486 2016 1,507 11,020 7,540,486 2017 1,507 11,020 7,540,486 201 8 1,507 11,020 7,540,486

2009 BUDGET FORECAST TOTAL EXISTING DSM PROGRAMS

CUMULATIVE ANNUAL REDUCTIONS AT GEINERATOR


2008 2009 201 0 201 1 201 2 2013 2014 201 5 2016 201 7 201 8

236,116 237,362 238,610 239,830 241,060 242,503 244,011 245,518 247,026 248,533 250,040

308,349 317,556 326,777 335,807 344,904 355,477 366,497 37751 6 388,536 399,555 41 0,575

566,719,775 572,975,983 579,242,558 585,373,105 591,551,559 598,775,846 606,316,332 613,856,818 621,397,304 628,937,791 636,478,277

36

HISTORICAL RESIDENTIAL EXISTING DSM PROGRAMS



PEAK (KW)

PEAK (KW)

2007 123,926 196,253 308,686,245

2009 BUDGET FORECAST RESIDENTIAL EXISTING DSM PROGRAMS


2008 2009 2010 201 1 2012 201 3 2014 201 5 2016 201 7 201 8

SUMMER

PEAK (KW)

1,127 1,246 1,248 1,220 1,230 1,443 1,507 1,507 1,507 1,507 1,507

WINTER NET ENERGY

PEAK (KW)

8,385 9,207 9,221 9,030 9,097

10,573 11,020 11,020 11,020 11,020 11,020

5,673,680 6,256,208 6,266,575 6,130,547 6,178,454 7,224,287 7,540,486 7,540,486 7,540,486 7,540,486 7,540,486

2009 BUDGET FORECAST RESIDENTIAL EXISTING DSM PROGRAMS



2008 2009 201 0 201 1 201 2 201 3 2014 201 5 2016 201 7 201 8

PEAK (KW)

125,053 126,299 127,547 128,767 129,998 131,441 132,948 134,455 135,963 137,470 138,977

PEAK (KW)

204,638 213,845 223,066 232,096 241,193 251,766 262,786 273,805 284,825 295,844 306,864

31 4,359,925 320,616,133 326,882,708 333,013,255 339,191,709 346,415,996 353,956,482 361,496,968 369,037,454 376,577,941 384,118,427

37

H I S'TORI CAL COMMERCIAL EXISTING DSM PROGRAMS

CUMULATIVE ANNUAL REDUCTIONS AT GEiNERATOR


2007 11 1,063 103,711 241,278,930

2009 BUDGET FORECAST COMMERCIAL EXISTING DSM PROGRAMS

AT GEiNERATOR INCREMENTAL ANNUAL REDUCTIONS


2008 2009 201 0 201 1 2012 201 3 2014 2015 2016 201 7 2018

2009 BUDGET FORECAST COMMERCIAL EXISTING DSM PROGRAMS



2008 2009 201 0 201 1 201 2 201 3 2014 201 5 201 6 201 7 201 8

111,063 1 11,063 11 1,063 11 1,063 111,063 11 1,063 111,063 111,063 111,063 111,063 11 1,063

103,711 103,711 103,711 103,711 103,711 103,711 103,711 103,711 103,711 103,711 103,711

241,278,930 241,278,930 241,278,930 241,278,930 241,278,930 241,278,930 241,278,930 241,278,930 241,278,930 241,278,930 241,278,930

38

H ISTORI CAL OTHER EXISTING DSM PROGRAMS CUM U LATl VE ANNUAL RE DUCT1 ON S

AT GENERATOR


2007

PEAK (KW)

PEAK (KW)

11,080,920

2009 BUDGET FORECAST OTHER EXISTING DSM PROGRAMS



2008 2009 201 0 201 1 2012 201 3 2014 201 5 2016 2017 2018

PEAK (KW)

PEAK (KW)

2009 BUDGET FORECAST OTHER EXISTING DSM PROGRAMS CUMULATIVE ANNUAL REDUCTIONS

AT GENERATOR


2008 2009 201 0 201 1 201 2 201 3 2014 201 5 2016 2017 201 8

PEAK (KW)

PEAK (KW)

FOR LOAD (KWW

11,080,920 11,080,920 11,080,920 11,080,920 11,080,920 11,080,920 11,080,920 11,080,920 11,080,920 11,080,920 11,080,920

39

H IS TORICAL TOTAL NEW DSM PROGRAMS



2007 120,491 120,324 140,878,551

2009 BUDGET FORECAST TOTAL NEW DSM PROGRAMS

I N C REMENTAL ANN U AL REDUCTIONS AT GENERATOR

SUMMEF! WINTER NET ENERGY

2008 2009 201 0 201 1 2012 201 3 2014 2015 2016 2017 201 8

4,209 7,130 7,002 7,002 7,002 7,002 7,002 7,002 7,002 7,002 7,002

4,701 8,122 8,200 8,200 8,200 8,200 8,200 8,200 7,964 7,964 7,964

6,590,683 8,866,004 8,796,322 8,796,322 8,796,322 8,796,322 8,796,322 8,796,322 8,484,315 8,484,315 8,484,315

2009 BUDGET FORECAST TOTAL NEW DSM PROGRAMS


SUMMEF! WINTER NET ENERGY

2008 2009 201 0 201 1 2012 2013 2014 201 5 2016 201 7 201 8

124,700 131,830 138,832 145,833 152,835 159,837 166,839 173,840 180,842 187,844 194,846

125,025 1 33,148 141,347 149,547 157,747 165,947 174,147 1 82,346 190,310 198,273 206,237

147,469,234 156,335,238 165,131,560 173,927,882 182,724,204 191,520,527 200,316,849 209,113,171 217,597,486 226,081,801 234,566,116

40

HISTORICAL RESIDENTIAL NEW DSM PROGRAMS C UMU LATl VE ANNUAL REDUCTIONS

AT GENERATOR


PEAK (KW)

PEAK (KW)

2007 51,450 78,322 55,029,240

2009 BUDGET FORECAST RESIDENTIAL NEW DSM PROGRAMS INCREMENTAL ANNUAL REDUCTIONS

AT GENERATOR

2008 2009 201 0 201 1 2012 201 3 2014 201 5 2016 2017 201 8

SUMMER

PEAK (KW)

4,209 7,130 7,002 7,002 7,002 7,002 7,002 7,002 7,002 7,002 7,002

WINTER NET ENERGY

PEAK (KW)

4,701 8,122 8,200 8,200 8,200 8,200 8,200 8,200 7,964 7,964 7,964

6,590,683 8,866,004 8,796,322 8,796,322 8,796,322 8,796,322 8,796,322 8,796,322 8,484,315 8,484,315 8,484,315

2009 BUDGET FORECAST RESIDENTIAL NEW DSM PROGRAMS CUMULATIVE ANNUAL REDUCTIONS

AT GENERATOR


2008 2009 201 0 201 1 2012 2013 2014 201 5 2016 2017 201 8

PEAK (KW)

54,326 59,672 64,889 70'1 06 75,323 80,540 85,758 90,975 96,192

101,409 106,626

PEAK (KW)

82,331 89,491 96,730

103,968 11 1,207 1 18,445 125,684 132,922 139,925 146,927 153,929

58,223,975 62,698,964 67,104,271 71,509,578 7591 4,885 80,320,192 84,725,498 89,130,805 93,224,105 97,317,406

101,410,706

41

HIS'TORICAL COMMERCIAL/INDUSTRIAL NEW DSM CUMULATIVE ANNUAL REDUCTIONS

AT GEENERATOR



69,041 42,002 85,849,311

2009 BUDGET FORECAST COMMERCIAUINDUSTRIAL NEW DSM INCREMENTAL ANNUAL REDUCTIONS

AT GE!NERATOR

2007

2008 2009 201 0 201 1 201 2 201 3 2014 201 5 201 6 2017 2018

SUMMER

PEAK (KW)

1,332 1,785 1,785 1,785 1,785 1,785 1,785 1,785 1,785 1,785 1,785

WINTER NET ENERGY

PEAK (KW)

693 96 1 96 1 96 1 96 1 96 1 96 1 961 961 961 961

3,395,948 4,391,015 4,391,015 4,391,015 4,391,015 4,391,015 4,391,015 4,391,015 4,391,015 4,391,015 4,391,015

2009 BUDGET FORECAST COMMERCIAL/INDUSTRIAL NEW DSM CUMULATIVE AINNUAL REDUCTIONS

AT GENERATOR

2008 2009 2010 201 1 2012 201 3 2014 2015 2016 2017 2018

SUMMER:

PEAK (KW)

70,373 72,158 73,943 75,727 77,512 79,296 81,081 82,866 84,650 86,435 88,220

WINTER NET ENERGY

PEAK (KW)

42,695 43,656 44,617 45,579 46,540 47,501 48,463 49,424 50,385 51,347 52,308

89,245,259 93,636,274 98,027,290

102,418,305 106,809,320 11 1,200,335 115,591,350 119,982,365 124,373,381 1 28,764,396 133,155,411

42

HISTORICAL OTHER NEW DSM PROGRAMS


2007


PEAK PEAK FOR LOAD

(KW) (KW) (KWH1

2009 BUDGET FORECAST OTHER NEW DSM PROGRAMS



PEAK PEAK FOR LOAD

(KW) (KW) (KWH)

2008 2009 201 0 201 1 201 2 201 3 2014 201 5 201 6 201 7 201 8

2009 BUDGET FORECAST OTHER NEW DSM PROGRAMS



PEAK PEAK FOR LOAD

(KW) (KW) (KWH)

2008 2009 201 0 201 1 2012 201 3 2014 201 5 201 6 201 7 201 8

43

VII. SMALL POWER PRODUCTION I RENEWABLE ENERGY

The current forecasts also consider Gulfs active position in the

promotion of renewable energy resources. Gulf initiated implementation of a

renewable energy program, Solar for Schools, to obtain funding for the

installation of solar technologies in participating school facilities combined with

energy conservation education of students. Initial solicitation began in

September 1996 and has resulted in participation of approximately 208

customers contributing $73,800 through December, 2008. Four small solar

photovoltaic (PV) demonstration systems have been installed throughout

Northwest Florida as part of this program.

Gulf customers also now have the opportunity to participate in a FPSC-

approved ”green pricing” alternative. Rate Rider PV gives customers an

opportunity to help pay for the construction of a photovoltaic generating facility.

This project is a Southern Company-wide effort; with Gulf and her sister

company Alabama Power Company the first to roll out their programs. The

facility will be built within Southern Company’s service area or the power will be

purchased from other photovoltaic generating facilities. Approximately 10,000

customers are initially needed to sign up in order to begin construction of a one

MW generating facility. As of December, 2008, 57 customers have pledged to

purchase a total of 73 hundred-watl. blocks of generation at a monthly rate of $6

per block. The time frame for potential construction will be determined as

participation levels increase.

44

Please refer to the Capacity Resource Alternatives section of this TYSP

for additional information concerning Gulf's efforts to promote and develop

renewable energy resources.

45

- Year 1999 2000 2001 2002 2003 2004 2005 2006 2007

Q\ 2008

2009 201 0 201 1 201 2 201 3 2014 201 5 2016 2017 2018

CAAG 99-08 08-1 3 08-1 8

GULF POWER COMPANY

Schedule 2.1 History and Forecast of Energy Consumption and

Number of Customers by Customer Class

(2) (3) (4) (5) (6)

Rural and Residential Average KWH

PoDulation 812,993 828,849 844,139 860,642 879,011 896,851 909,608 937,329 964,349 969,757

984,111 997,130

1,015,404 1,034,738 1,055,254 1,076,192 1,098,065 1 , I 1 9,994 1,145,674 1,166,713

2.0% 1.7% 1.9%

Members Per

Household 2.60 2.59 2.59 2.60 2.60 2.60 2.60 2.60 2.60 2.59

2.58 2.57 2.56 2.55 2.54 2.53 2.52 2.51 2.51 2.50

-0.1% -0.4% -0.3%

GWH 4,471 4,790 4,716 5,144 5,101 5,215 5,320 5,425 5,477 5,349

5,676 5,842 6,063 6,243 6,423 6,579 6,737 6,934 7,161 7,392

2.0% 3.7% 3.3%

Average No. of

Customers 312,283 319,506 325,343 331,637 338,631 345,467 350,404 360,y3u

371,213 374,709

381,719 388,248 396,873 405,979 415,621 425,504 435,835 446,270 456,472 466,676

2.0% 2.1% 2.2%

Consumption Per Customer

14,318 14,992 14,497 15,510 15,064 15,096 15,181 i 5,032 14,755 14,274

14,868 15,048 15,276 15,377 15,453 15,461 15,458 15,537 15,687 15,839

0.0% 1.6% 1 .O%

Commercial Average KWH

GWH 3,223 3,379 3,417 3,553 3,614 3,695 3,736 3,843 3,971 3,961

3,962 4,054 4,213 4,336 4,457 4,560 4,663 4,797 4,960 5,125

2.3% 2.4% 2.6%

Average No. of

Customers 47,294 47,584 48,482 49,139 50,419 51,981 52,916 53,479 53,791 53,810

54,572 55,448 56,597 57,806 59,080 60,387 61,749 63,130 64,491 65,860

1.4% 1.9% 2.0%

Consumption Per Customer

68,138 71,020 70,490 72,304 71,684 71,093 70,599 1-1 ,UOL

73,821 73.610

^^^

72,594 73,115 74,442 75,014 75,436 75,508 75,511 3 75,984 76,917 77,823

0.9% 0.5% 0.6%

* Historical and projected figures include portions of Escambia, Santa Rosa, Okaloosa, Bay,

GULF POWER COMPANY



(3) (7) (4)

Industrial Average Average KWH

No. of Consumption Customers Per Customer

249 7,409,647 269 7,141,925 277 7,290,329 272 7,552,563 285 7,526,577 279 7,569,053 295 7,332,898 294 7,260,626 303 6,769,670 291 7,592,204

Street & Highway Lighting GWH

18 18 21 21 22 23 23 24 24 23

Other Sales to Public

Authorities GWH

0 0 0 0 0 0 0 0 0 0

Total Sales to Ultimate Consumers

GWH 9,558 10,112 10,173 10,772 10,885 11,046 11,239 11,429 11,521 11,543

Railroads and Railways

GWH 0 0 0 0 0 0 0 0 0 0

- Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

GWH 1,846 1,925 2,018 2,054 2,147 2,113 2,161 2,136 2,048 2,211

P 4

2009 201 0 201 1 2012 201 3 2014 201 5 2016 2017 2018

2,147 2,183 2,195 2,185 2,172 2,162 2,150 2,137 2,130 2,141

307 312 317 32 1 324 328 331 336 340 343

6,996,432 6,992,47 1 6,934,888 6,814,562 6,711,904 6,593,011 6,485,449 6,367,537 6,263,425 6,233,940

0 0 0 0 0 0 0 0 0 0

24 25 26 28 29 30 31 33 34 36

11,809 12,105 12,498 12,791 13,080 13,330 13,581 13,901 14,286 14.695

0 0 0 0 0 0 0 0 0 0

CAAG 99-08 08-1 3 08-1 8

2.0% -0.3% -0.3%

1.7% 2.1% 1.7%

0.3% -2.4% -2.0%

0.0% 0.0% 0.0%

2.6% 4.4% 4.5%

0.0% 0.0% 0.0%

2.1% 2.5% 2.4%

GULF POWER COMPANY

P 00

Year 1999 2000 2001 2002 2003 2004 2005 2006

2008

clnn7 LUU I

2009 2010 201 1 2012 201 3 2014 201 5 2016 2017 2018

CAAG 99-08 08-1 3 08-1 8

Sales for Resale GWH 348 363 360 384 383 389 41 8 41 5

398 A 4 7 I t l l

386 393 398 405 412 420 428 436 445 453

1.5% 0.7% 1.3%



(3)

Utility Use & Losses

GWH 559 628 671 754 685 727 666 743 733 653

775 796 82 1 84 1 860 876 893 914 939 965

1.7% 5.6% 4.0%

(4)

Net Energy for Load

GWH 10,467 11,105 11,204 11,910 11,952 12,162 12,322 12,586 12,671 12,595

12,970 13,294 13,717 14,036 14,352 14,627 14,903 15,251 15,669 16,112

2.1% 2.6% 2.5%

(5)

Other Customers

{Average No.) 286 380 460 474 473 474 472 482

493 A QC: 7""

495 498 502 505 509 51 3 516 520 524 528

6.2% 0.6% 0.7%

Total No. of

Customers 360,113 367,740 374,56 1 381,521 389,809 398,200 404,086 41 5,185 425,793 429.302

437,093 444,506 454,288 464,611 475,533 486,731 498,432 51 0,256 52 1 ,826 533,407

2.0% 2.1% 2.2%

Note: Sales for Resale and Net Energy for Load include contracted energy allocated to certain customers by Southeastern Power Administration (SEPA).

GULF POWER COMPANY

Schedule 3.1 History and Forecast of Summer Peak Demand - MW

Base Case

(3) (4) (7) (9)

Residential Load

Manaaement 0 0 0 0 0 0 0 0 0 0

Comm/l nd Load

Manaqement 0 0 0 0 0 0 0 0 0 0

Residential Conservation

120 128 137 145 153 161 167 173 177 179

Commllnd Conservation

143 142 143 148 155 159 164 168 174 175

Net Firm Demand 2,169 2,289 2,231 2,462 2,275 2,431 2,435 2,483 2,634 2,541

- Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

2009 201 0 201 1 2012 201 3 2014 201 5 2016 201 7 201 8

- Total 2,448 2,558 2,528 2,755 2,583 2,751 2,767 2,824 2,985 2,895

2,970 3,040 3,132 3,180 3,252 3,320 3,391 3,446 3,536 3,632

Wholesale 84 86 78 86 79 84 82 89 95 88

88 89 90 91 92 93 95 96 98 99

Retail 2,363 2,472 2,450 2,669 2,504 2,666 2,685 2,735 2,890 2,807

lnterrwtible 16 0 17 0 0 0 0 0 0 0

2,882 2,951 3,042 3,089 3,160 3,227 3,296 3,350 3,438 3,533

0 0 0 0 0 0 0 0 0 0

0 0 0 0 0 0 0 0 0 0

1 84 191 197 204 21 0 21 7 224 230 237 242

0 0 0 0 0 0 0 0 0 0

178 179 181 183 185 186 188 190 192 1 94

2,608 2,670 2,754 2,794 2,857 2,917 2,979 3,026 3,107 3,196

CAAG 99-08 1.9% 08-13 2.4% 08-18 2.3%

1.9% 2.4% 2.3%

0.0% 0.0% 0.0%

0.0% 0.0% 0.0%

4.6% 3.3% 3.1%

0.0% 0.0% 0.0%

2.3% 1 .O% 1 .O%

1.8% 2.4% 2.3%

0.5% 0.8% 1.1%

NOTE 1 : Includes contracted capacity and energy allocated to certain Resale customers by Southeastern Power Administration (SEPA) NOTE 2: The forecasted interruptible amounts shown in col (5) are included here for information purposes only. The projected demands shown

in column (2), column (4) and column ( I O ) do not reflect the impacts of interruptible. Gulf treats interruptible as a supply side resource.

GULF POWER COMPANY

- Year Total 98-99 2,392 99-00 2,225 00-01 2,486 01-02 2,530 02-03 2,857 03-04 2,445 04-05 2,518 05-06 2,475 06-07 2,643 07-08 2,791

08-09 2,759 09-10 2,856 10-11 2,953 11-12 3,036 12-13 3,121 13-14 3,183 14-15 3,242 15-16 3,325 16-17 3,426 17-18 3,505 18-19 3,593 CAAG 99-08 1.7% 08-13 2.3% 08-18 2.3%

(3)

Wholesale 79 75 86 85 92 76 89 89

94

81 82 83 74 75 76 77 79 80 85 86

1.9% -4.3% -1 .O%

Q K "V

(4)

Retail 2,313 2,150 2,401 2,445 2,766 2,369 2,428 2,386 2,558 2,698

2,678 2,774 2,870 2,962 3,046 3,107 3,165 3,246 3,346 3,420 3,507

1.7% 2.5% 2.4%

Schedule 3.2 History and Forecast of Winter Peak Demand - MW

Base Case

InterruDti ble 0 0 0 0 0 0 0 0 c! 0

0 0 0 0 0 0 0 0 0 0 0

0.0% 0.0% 0.0%

(6)

Residential Load

Manaaement 0 0 0 0 0 0 0 0 c! 0

0 0 0 0 0 0 0 0 0 0 0

0.0% 0.0% 0.0%

(7)


177 188 200 21 1 225 240 250 263 276 277

294 31 0 327 343 361 379 397 41 5 433 440 447

5.1% 5.4% 4.7%

Commllnd Load

Manaaement 0 0 0 0 0 0 0 0 n 0

0 0 0 0 0 0 0 0 0 0 0

0.0% 0.0% 0.0%

(9)

Commllnd Conservation

122 126 126 129 133 134 137 140 I 4 3 144

145 146 147 148 149 150 151 152 153 154 155

1.8% 0.7% 0.7%

Net Firm Demand 2,093 1,911 2,160 2,190 2,500 2,070 2,130 2,072 2,224 2,370

2,320 2,399 2,479 2,545 2,611 2,654 2,694 2,758 2,840 2,911 2,991

1.4% 2.0% 2.1%

NOTE 1 : Includes contracted capacity and energy allocated to certain Resale customers by Southeastern Power Administration (SEPA) NOTE 2: The forecasted interruptible amounts shown in col (5) are included here for information purposes only. The projected demands shown

in column (2), column (4) and column ( I O ) do not reflect the impacts of interruptible. Gulf treats interruptible as a supply side resource.

GULF POWER COMPANY

Schedule 3.3 History and Forecast of Annual Net Energy for Load - GWH

Base Case

(3) (4) (5) (7) (9)


297 305 314 323 335 348 357 366 376 379

390 400 41 1 42 1 433 445 457 469 480 484

Comm/lnd Conservation

2 74 280 284 288 297 303 31 9 325 329 333

338 342 347 351 355 360 364 368 373 377

Utility Use & Losses

559 628 671 754 685 727 666 743 733 653

Net Energy for Load 10,467 11,105 11,204 11,910 11,952 12,162 12,322 12,586 12,671 12,595

Load Factor %

55.1 % 55.2% 57.3% 55.2% 60.0% 57.0% 57.8% 57.9% 54.9% 56.4%

Year 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

2009 201 0 201 1 2012 201 3 2014 2015 2016 201 7 201 8

CAAG - 99-08 08-1 3 08-1 8

j%taJ 11,038 11,690

Retail 9,559 10,113

Wholesale 348 363 360 384 383 389 41 8 41 5 41 7 398

386 393 398 405 412 420 428 436 445 453

1,801 2,520 2,584 2,813 2,998 3,277

13,377 13,307

13,697 14,036 14,475 14,809 15,141 15,432 15,724 16,088 16,522 16.974

0,173 0,772 0,885 1,046 1,239 1,429

11,521 11,543

11,809 12,105 12,498 12,791 13,080 13,330 13,581 13,901 14,286 14.695

56.8% 56.8% 56.9% 57.2% 57.3% 57.2% 57.1% 57.4% 57.6% 57.6%

775 796 82 1 84 1 860 876 893 914 939 965

12,970 13,294 13,717 14,036 14,352 14,627 14,903 15,251 15,669 16,112

2.1% 2.6% 2.5%

2.7% 2.7% 2.5%

2.2% 1.3% 1.3%

2.1% 2.5% 2.4%

1.5% 0.7% 1.3%

1.7% 5.6% 4.0%

2.1% 2.6% 2.5%

0.3% 0.3% 0.2%

NOTE: Wholesale and total columns include contracted capacity and energy allocated to certain Resale customers by Southeastern Power Administration (SEPA).

GULF POWER COMPANY

Schedule 4 Previous Year Actual and Two Year Forecast of Peak Demand and Net Energy for Load by Month

Month January February March April

June July August September October N ovem be r December

VI May h,

2008 Actual

Peak Demand NEL - MW

2,362 2,147 1,850 1 ;692 2,215 2 , 390 2,533 2,521 2,327 1,918 1,888 1,801

GWH 1,055 860 880 900

1,085 1,276 1,358 1,298 1,174 964 852 893

2009 Forecast

Peak Demand NEL MW

2,376 2,185 1,827 1.910 2,252 2,402 2,608 2,601 2,510 2,107 1,834 2,229

GWH 1,052 889 924 942

1,135 1,239 1,362 1,380 1,145 1,002 886

1,014

201 0 Forecast

Peak Demand NEL - MW GWH

2,399 1,064 2,223 905 1,847 934 1,937 957 2,339 1,179 2,450 1,266 2,670 1,398 2,657 1,412 2,575 1,176 2,173 1,035 1,897 917 2 , 304 1,050

NOTE: includes contracted capacity and energy allocated to certain Resale customers by Southeastern Power Administration (SEPA)

Gulf Power Company

Schedule 5 Fuel Requirements

(3) (4) (5) (7) (9)

Actual Actual Fuel Requirements Units 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

(1) Nuclear

(2) Coal

(3) Residual (4) (5) (6) (7)

(17) Other

Total Steam cc CT Diesel


Total Steam cc CT

Trillion BTU

1000 TON

1000 BBL 1000 BBL 1000 BBL 1000 BBL 1000 BBL

1000 BBL 1000 BBL 1000 BBL 1000 BBL 1000 BBL

1000 MCF 1000 MCF 1000 MCF 1000 MCF

Trillion BTU

None

6.793

0 0

None None None

13 11

None 2

None

14,830 155

14,675 0

None

None

5,891

0 0

None None None

15 14

None 1

None

16,961 185

16,776 0

None

None

5,826

0 0

None None None

9 9

None 0

None

15,360 0

13,709 1,651

None

None

6.075

0 0

None None None

8 8

None 0

None

20,534 0

19.162 1.372

0.2

None

6,025

0 0

None None None

8 8

None 0

None

13,774 0

12,339 1,435

0.2

None

5,644

0 0

None None None

9 8

None 1

None

15,802 0

14,073 1,729

0.2

None

5,929

0 0

None None None

8 7

None 1

None

16,545 0

14,664 1,881

4.7

None

5,882

0 0

None None None

7 7

None 0

None

28,901 0

28.795 106

9.1

None

5,781

0 0

None None None

7 7

None 0

None

37,572 0

37,572 0

9.1

None

5,616

0 0

None None None

9 9

None 0

None

38,152 0

38,152 0

9 1

None

5,982

0 0

None None None

7

None 0

None

39,074 0

39,074 0

7

9 1

None

5 734

0 0

None None None

7

Nane 0

None

38,007 0

38.007 0

7

9 1

Utility: Gulf Power Company

Schedule 6.1 Energy Sources

(7) (8) (9) (3) (4) (6)

Actual 2008

(2,209)

None

(5)

Actual 2007

(4,043)

None

2009 2010 2011

(2,620) (3,555) (I ,974)

--- 2017 2018 -- 201 5

(4,407)

None

12.932

201 6

(3,765)

None

12,552

201 3

(1,792)

None

2014

(3,612)

None

EnerQy Sources

(1) Annual Firm Interchange

(2) Nuclear

(3) Coal

(4) Residual Total (5) Steam (6) (7) (8)

(9) Distillate Total (10) Steam (11) cc

CT Diesel

(12) (13)

(14) Natural Gas Total (1 5) Steam

(17) CT

(18) NUGs

(1 9) Net Energy for Load

cc CT Diesel

(1 6) cc

Units

GWH

GWH

(4,316) (3,153)

None None

13,382 12 799

0 0 0 0

None None None None None None

None None None None

GWH 14,281 12.334 13:427 13,783 13,626

0 0 0 0 0 0

None None None None None None None None None

12,826 13,385

0 0

None None None

13.169

0 0

None None None

0 0

None None None

0 None None

0 None

0 0

None None None

0 Nons None

0 None

0 0

None None None

0 None None

0 None

GWH GWH GWH GWH GWH

0 0

None None None

0 0

None None None

wl P

0 0 None None None None

0 0 None None

GWH GWH GWH GWH GWH

GWH GWH GWH GWH

1 None None

None 1

1 None None

None 1

0 0 0 None None None None None None

0 0 0 None None None

1 None None

None 1

1 None None

None 1

2,374 10

2.31 5 49

2,428

2,373 47

a 2,111 2,998 1,988

0 0 0 1,958 2,758 1,742 153 240 246

2,242 0

1,970 272

2,336 0

2,050 286

422

4,324 0

4.202 122

746

5,658 0

5,545 113

5,741 0

5,628 113

5,878 5,737 0 0

5765 5624 113 3 13

720 723 725 729 GWH 53 41 52 68 77

12,970 13.294 13.717

73

14,036 14,352 14,627 14,903 15,251 15.569 16,l 12 GWH 12,671 12,595

NOTE: Line (1 8) includes energy purchased from Non-Renewable and Renewable resources, as well as energy from Gulf-owned Renewable resources shown on Schedule 8 .

VI VI

(3)

Energy Sources

(1) Annual Firm Interchange

(2) Nuclear

(3) Coal

(18) NUGs

(1 9) Net Energy for Load



Total Steam cc CT

(4)

Units

%

%

%

% % % % %

% Yo % % %

% % % %

%

%

(5)

Actual 2007

(31.91)

None

112.71

0.00 0.00 None None None

0.01 None None 0.01 None

18.74 0.08

18.27 0.39

0.46

100.00

Utility: Gulf Power Company

Schedule 6.2 Energy Sources

(6) (7) (8) (9)

Actual 2008 2009 2010 2011 - - ~ -

(17.54)

None

97.93



19.28 0.06

18.84 0.37

0.33

100.00

(20.20)

None

103.52



16.28 0.00

15.10 1.18

0.40

100.00

(26.74)

None

103.68



22.55 0.00

20.75 1.81

0.51

100.00

(14.39)

None

99.34



14.49 0.00

12.70 1.79

0.56

100.00

(1 0)

2012

(7.92)

None

91.38



15.97 0.00

14.04 1.94

0.56

100.00

(11)

201 3

(12.49)

None

93.26



16.28 0.00

14.28 1.99

2.94

100.00

(12)

2014

(24.69)

None

90.03



29.56 0.00

28.73 0.83

5.10

100.00

(1 3)

201 5

(29.57)

None

86.77



37.97 0.00

37.21 0.76

4.83

100.00

(14)

2016

(24.69)

None

82.30



37.64 0.00

36.90 0.74

4.74

100.00

(15)

201 7

(27.54)

None

85.40



37.51 0.00

36.79 0.72

4.63

100.00

(1 6)

2018

(19.57)

None

79.44



35.61 0.00

34.91 0.70

4.52

100.00

Utility: Gulf Power Company Schedule 6.3

Renewable Energy Sources

(2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (1 3) Actuals

(1)

Renewable Energy Sources (A) 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 (1) Renewable Generating Capacity

MW 0 0 3 3 3 95 95 95 95 95 95 MWh 37,244 48,180 63,510 71,832 71,832 414,348 736,789 708,684 708,684 708,684 708,684

% of Capacity Mix nla nla < I < I < I 3.0 2.7 2.7 2.7 2.7 2.7 %ofNEL < I < I < I < I e l 3.1 5.4 5.1 4.9 4.8 4.7

% of Fuel Mix 1 < I < I < I < I 2.6 4.0 3.7 3.7 3.5 3.7

(2) Self-service Generation By Renewable Generation MW 68 68 68 68 68 68 68 68 68 68 68

MWh (B) varies varies varies varies varies varies varies varies varies varies varies

(A) Owned andlor Purchased by Gulf. (B) Energy produced by these customers' generators varies depending on demand for their product.

CHAPTER 111

PLANNING ASSUMPTIONS AND PROCESSES

THE INTEGRATED RElSOURCE PLANNING PROCESS

As previously mentioned, Gulf participates in the SES IRP process. This

process begins with a team of experts from within and outside the SES that

meets to discuss current and historical economic trends and conditions, as well

as future expected economic conditiolns which would impact the SES's business

over the next twenty to twenty-five years. This economic panel determines the

various escalation and inflation rates that will impact the financial condition of the

SES. This determination acts as a basis for developing the general inflation and

escalation assumptions that will affect fuel costs, construction costs, labor rates

and variable O&M.

In addition to the work of the economic panel, there are a number of

activities that are conducted in parallel with one another in the IRP process.

These activities include energy and demand forecasting, fuel price forecasting,

technology screening analysis and evaluation, engineering cost estimation

modeling, evaluation of active and passive demand-side options, and other

miscellaneous issues. The SES operating companies have also remained active

in offering customers programs and ciptions which result in modified consumption

patterns. An important input into the design of such demand-side programs is an

assessment of their likely impact on system loads.

Gulf's forecast of energy sales and peak demand reflects the continued

impacts of its conservation program:;. Furthermore, an update of demand-side

57

measure cost and benefits is conducted in order to perform cost-effectiveness

evaluations against the selected supply-side technologies from the IRP process.

A number of existing generating units on the SES are also evaluated with

respect to their currently planned retirement dates, as well as the economics and

appropriateness of possible repowering over the planning horizon. These

evaluations are extremely important in order to maximize the benefit of existing

investment from both a capital and an operations and maintenance expense

perspective.

Additionally, the market for potential power purchases is analyzed in order

to determine its cost-effectiveness in comparison to the available supply-side and

demand-side options. Power purchases are evaluated on both a near-term and

long-term basis as a possible means of meeting the system’s demand

requirements. These power purchases can be procured from utility sources as

well as from non-utility generators.

The supply side of the IRP process focuses on the SES as a whole, which

has as its planning criterion a 15% reserve margin target for the year 2012 and

beyond. This reserve margin is the optimum economic point at which the system

can meet its energy and demand requirements after accounting for load forecast

error, abnormal weather conditions, and unit-forced outage conditions. It also

balances the cost of adding additional generation with the societal cost of not

serving all the energy requirements of the customer.

Once the above mentioned planning assumptions are determined,

generating unit technologies are screened to determine the most acceptable

58

candidates, the necessary planning inputs are defined and the generation mix

analysis is initiated. The main optimization tool used in the generation mix

analysis is the PROVIEWO model. The supply-side technology candidates are

input into PROVIEWO in specific MMI block sizes for selection over the planning

horizon for the entire SES. Although this model uses many data inputs and

assumptions in the process of optimiizing system generation additions, the key

assumptions are load forecasts, demand-side options, candidate units, reserve

margin requirements, cost of capital, ;and escalation rates.

PROVIEWO uses a dynamic programming technique to develop the

optimum resource mix. This technique allows PROVIEWO to evaluate for every

year all the many combinations of generation additions that satisfy the reserve

margin constraint. Annual system operating costs are simulated and are added

to the construction costs required to build each combination of resource

additions. A least cost resource addition schedule is developed by evaluating

each year sequentially and comparing the results of each combination. A least

cost resource plan is developed only after reviewing many construction options.

PROVIEW@ produces a number of different combinations over the

planning horizon, evaluating both the capital cost components for unit additions

as well as the operating and maintenance cost of existing and future supply

option additions. The program produces a report which ranks all of the different

combinations with respect to the taltal net present value cost over the entire

twenty-year planning horizon. The leading combinations from the program are

then evaluated for reasonableness and validity. Once again, it is important to

59

note that supply option additions from the PROVIEWB program output are for the

entire SES and are reflective of the various technology candidates selected.

After the SES results are verified, each individual operating company’s

specific needs over the planning horizon are evaluated. Each company is

involved in recommending the type and timing of its unit additions. When all

companies are satisfied with their capacity additions, and the sum of these

additions matches the system need, the system base supply-side plan is

complete. The result is an individual operating company supply plan that fits

within the SES planning criteria.

Once the individual operating company supply plans are determined, it is

necessary to evaluate demand-side options as a cost-effective alternative to the

supply plan additions. After the incorporation of the cost effective demand-side

impacts, a final integrated resource plan is produced.

Finally, a financial analysis of the impact of the plan is performed. The

plan is analyzed for changes in load forecast and fuel price variations in order to

assess the impact on the system’s cost. Once the plan has proven to be robust

and financially feasible, it is reviewed with and presented for approval to

executive management.

In summary, the SES IRP process involves a significant amount of

manpower and computer resources in order to produce a truly least-cost,

integrated demand-side and supply-side resource plan. During the entire

process, the SES is continually looking at a broad range of alternatives in order

to meet the SES’s projected demand and energy requirements. The SES

60

updates its IRP each year to account for the changes in the demand and energy

forecast, as well as the other major assumptions previously mentioned in this

section. A remix is then performed tci insure that the IRP is the most economical

and cost-effective plan. The resultiiig product of the SES IRP process is an

integrated plan which meets the needs of the SES’s customers in a cost-effective

and reliable manner.

TRANSMISSION PLAN N I N G PRO C ES S

The transmission system is not studied as a part of the IRP process, but it

is studied, nonetheless, for reliability purposes. Commonly, a transmission

system is viewed as a medium uised to transport electric power from its

generation source to the point of its conversion to distribution voltages under a

number of system conditions known as contingencies. The results of the IRP are

factored into transmission studies in order to determine the impacts of various

generation site options upon the transmission system. The transmission system

is studied under different contingencies for various load levels to insure that the

system can operate adequately without exceeding conductor thermal and system

voltage limits.

When the study reveals a potential problem with the transmission system

that warrants the consideration of correction in order to maintain or restore

reliability, a number of possible solutions are identified. These solutions and their

costs are evaluated to determine which is the most cost-effective. Once a

solution is chosen to correct the problem, a capital budget expenditure request is

61

prepared for executive approval. It should be noted that not all thermal overloads

or voltage limit violations warrant correction. This may be due to the small

magnitude of the problem or because the probability of occurrence is insufficient

to justify the capital investment of the solution.

In prior years, Gulf has entered into a series of purchased power

agreements to meet its needs, and it will continue this practice in the future when

economically attractive opportunities are available. The planned transmission

has proven adequate to handle these purchased power transactions during the

periods when Gulf has needed additional capacity. It has been and will continue

to be Gulf's practice to perform a transmission analysis of viable purchased

power proposals to determine any transmission constraints. Gulf will formulate a

plan, if needed, to resolve any transmission issues in a reasonable, cost effective

manner prior to proceeding with negotiations for purchased power agreements.

62

FUEL PRICE FORECAST PROCESS

FUEL PRICE FORECASTS

Fuel price forecasts are used for a variety of purposes within the Southern

Electric System (SES), including such diverse uses as long-term generation

planning and short-term fuel budgeting. The SES fuel price forecasting process

is designed to support these various uses.

The delivered price of any fuel consists of a variety of components. The

main components are commodity price and transportation cost. Coal commodity

domestic prices are forecast on either a mine-mouth basis or freight on board

(FOB) barge basis, while import coals are forecast on an FOB ship basis at the

port of export. Natural gas prices are forecast at the Henry Hub, Louisiana

benchmark delivery point. Because mine-mouth coal prices vary by source,

sulfur content, and Btu level, the SES prepares commodity price forecasts for

fifteen different coal classifications used on the SES. Because natural gas does

not possess the same quality variaitions as coal, the SES prepares a single

commodity price forecast for gas at Henry Hub, and applies a historical basis

differential between Henry Hub and the various pipelines serving SES plants.

Four price forecasts are developed for oil, based on grade of oil, sulfur, and heat

content

The level of detail with which transportation costs are projected depends

on the purpose for which the forecast will be used. Generic transportation costs,

reflecting an average cost for delivery within the SES service area, are used in

the delivered price forecast when modeling generic unit additions in the IRP

63

process. Site-specific transportation costs are developed for existing units to

produce delivered price forecasts for both the IRP process and the fuel budget

process. Similarly, when site-specific unit additions are under consideration, site-

specific transportation costs are developed for each option.

SES GENERIC FUEL FORECAST

Each year, SES develops a fuel price forecast for coal, oil, and natural gas

which extends through the Company’s IO-year planning horizon. This forecast is

developed by Southern Company Services (SCS) Fuel Procurement staff with

input from outside consultants. The forecast is approved by the fuel procurement

managers at each of the SES operating companies responsible for the fuel

programs at that company.

The fuel price forecast process begins with an annual Fossil Fuel Price

Workshop that is held with representatives from recognized leaders in energy-

related economic forecasting and transportation-related industries. Presenters at

the 2008 Fuel Price Workshop included representatives from Energy Ventures

Analysis, ICF Consulting, McCloskey Coal, Cambridge Energy Research

Associates, Criton Corp, Simpson Spence and Young, and PlRA Energy Group.

During the Fossil Fuel Price Workshop, each fuel representative presents

their “base case” forecast and assumptions. High and low fuel price scenarios

are also presented.

After the workshop, the SCS Fuel Procurement staff references the

outside consultant forecasts and identifies any major assumption differences.

The Fuel Procurement staff then consolidates both the internal and external

64

forecasts and assumptions to develop a commodity forecast for each type of fuel.

Fuel Procurement’s 2008 commodity price forecasts for bituminous 1 .O% sulfur

coal, natural gas and low sulfur #2 oil are included in the table below.

SES GENERIC FUEL PRICE FORECAST ($r’M M Btu)

2009

201 0

201 1

2012

201 3

2014

201 5

201 6

201 7

201 8

COAL*

4.583

4.167

3.750

3.333

2.91 7

2.880

2.958

3.041

3.125

3.233

NAT. GAS**

11.500

10.750

10.500

11.390

12.280

12.567

13.106

13.165

13.387

13.641

0 I L***

21.917

28.295

27.102

25.909

24.71 6

24.240

23.733

24.805

25.914

27.067

*Central Appalachia CSX, 12000 Btu/lb., 1% Sulfur

**Henry Hub

***U.S. Gulf Coast LS No.2 Oil, 0.05%, Sulfur

COAL PRICE FORECAST

In 2008, coal production in the United States reached 1,172 million short

tons, a 2.25% increase over year 2007 production levels. The Central

Appalachian region in the U.S. experienced a 3.7% increase in production.

Unlike the Central Appalachian region, the Interior region of the U.S. recorded a

65

15.8% decrease in production. The Western U.S. region, however, experienced

an 11 5% increase in production.

Total U.S. coal stockpiles increased during the year, as electric generators

built their stockpiles mainly in the second half of 2008 on milder weather and

improved rail transportation from the prior year as well as decreased demand

due to the global recession. At the same time, during the first half of 2008 the

expanding global economy (mainly driven by China) helped to increase the

demand for coal in the electric power sector during the year. There were no

significant delivery issues experienced in the U.S. market in 2008. In the world

market, China’s economic boom, coupled with production issues in Australia,

placed upward pressure on world coal pricing during the first half of 2008.

The coal industry continues to experience pricing pressure from

environmental and legal challenges, labor and mining cost increases, and more

recently, from a global recession. The increase in U.S coal market prices during

the first half of 2008 was primarily caused by world events, not U.S coal market

fundamentals. During the second half of 2008, world demand dropped as the

global recession grew in the summer and the financial collapse accelerated

events in September. Bituminous coal prices in the U.S. increased in real terms

through 1980 then declined in real terms through year 2000, after which real

price increases occurred through the first half of 2008. Sub-bituminous coal

prices declined in real terms through 2001 and have increased through the first

half of 2008. Spot market prices, during the first half of 2008, were relatively high

in nominal terms from the flat levels experienced in 2007 but then decreased

66

during the second half of 2008. The Central Appalachian, the Powder River

Basin, and the Western Colorado-U1:ah markets all saw price increases during

the first half of 2008 and price decreases during the second half, again due to the

global recession. Like its counterparts, import coal pricing into the U.S. from

Colombia saw the same pricing trend!; in 2008.

The generic coal prices used in the IRP process are based on an average

expectation of coal commodity costs combined with average transportation fees.

These generic coal prices are used in conjunction with plant-specific

transportation fees and plant-specific contract coal prices to develop the existing

fuel price projection for the SES annual budget process.

NATURAL GAS PRICE FORECAST

Counter to the trend of the last few years, supply has outpaced demand in

the 2008 gas market. Actual prices in the first half of 2008 tracked above the

forecast prepared in September ZOO;', then decreased rapidly during the second

half of 2008 and tracked below the forecast. Prices diverged from the forecast

during the second half of 2008 as a result of the combination of milder summer

weather, healthy levels of natural gas in storage, excess natural gas production

and declining demand due to the global economic slowdown. Gas-fired

generation increased slightly in the second half of 2008 as some natural gas

displaced coal, but the combination of high level of natural gas in storage and

decreasing demand resulted in lower natural gas prices towards the end of the

year. Despite the significant reduction in import volume of Liquefied Natural Gas

67

(LNG) from the previous year, the presence of LNG in the market offered a small

contribution towards the downward price pressure of natural gas.

Forward gas prices and analysts’ long-term price forecasts available

during the budget preparation for 2008 had shifted slightly downward from the

previous year The forward prices and forecasts showed an upward-sloping trend

in gas prices with the expectation that demand would continue to exceed supply.

The SES budget forecast anticipated stronger oil prices in both the near and

long-term due to strong, although slowing, worldwide economic growth and

continued tightening of capacity by OPEC. These forecasts did not assume any

impact from potential carbon legislation.

NATURAL GAS AVAILABILITY

Overall, domestic production is expected to decrease in the short term.

The global economic recession has caused natural gas demand to decline, but

the effect of increased production resulting from last year’s high natural gas

prices is still lingering. As producers reduced capital expenditures for 2009 by

shutting down drilling rigs, an eventual gas price increase in the 2009-2010

timeframe is foreseen. At present there is about 4 to 5 BCFD of excess supply in

the market, and several analysts are predicting near-term gas prices to average

in the $4.00-$5.00 range. Most of the oversupply is coming from unconventional

gas plays. Pipeline additions from these new gas plays are being developed and

are expected to be operational by the 2009 - 2010 timeframe. Adding to the

current oversupply situation is LNG imports. Total U.S. LNG imports were

68

estimated to have increased from 0.6 Bcfd in 2002 to approximately 1.8 Bcfd in

2004, were slightly reduced in 2005 and 2006, increased to an estimated 2.1

Bcfd in 2007, and then fell off to 0.9 Bcfd in 2008. A notable decrease in U.S.

LNG imports was observed in 2008 i3S strong global competition pulled cargoes

away from the U.S. market. However, due to the global economic downturn,

LNG imports are expected to increase in 2009, contributing to the current

oversupply situation. In the short run, LNG supply will continue to grow with new

liquefaction projects in Trinidad, Qatar, Norway, West Africa and elsewhere, but

substantial increases in LNG imports are not expected until the 2010 timeframe

or after due to delays in several of the overseas facilities becoming fully

operational.

Due to lower demand caused by the economic downturn and increases in

gas production, sufficient gas supply remains available to meet operating needs.

Pricing will remain soft in the near term as a result of the oversupply of gas

relative to demand. However, gas prices may increase due to a reduction in

drilling activity and the market’s reaction to weather events.

69

STRATEGIC ISSUES

Gulf has executed two PPAs that provide supply side flexibility and

diversity that will allow Gulf to react quickly to changing market conditions without

negative financial impacts to the Company and its customers. These PPAs will

supply firm dual-fuel fired peaking capacity to serve system load from June 2009

through May 2014.

Gulf's latest generation expansion plan, developed in conjunction with

other SES operating company planned capacity additions, indicates the need to

build or contract for new combined cycle (CC) generating capacity with an in-

service date of June 2014 in order to reliably meet Gulfs projected load growth.

On March 16, 2009, Gulf signed a PPA with a non-affiliated power marketer for

capacity and energy from an existing 885 MW gas-fired combined cycle

generating unit that is interconnected with the SES. This PPA is contingent upon

receipt of a final, non-appealable order from the FPSC for recovery of costs

associated with the PPA. This PPA, if approved by the FPSC, will secure a

resource to meet Gulf capacity needs in 2014 through the end of the 2009 TYSP

planning cycle.

The above-mentioned strategy of supplementing Gulf's development of

long-term capacity resources with shorter-term power purchases has proven

successful over the years, and Gulf will continue to follow this strategy when

appropriate and cost-effective to do so in the future.

70

Another important strategic adlvantage for Gulf is its association with the

SES as it relates to integrated planning and operations. Drawing on the planning

resources of Southern Company Services (SCS) to perform coordinated planning

and having the capacity resources of the SES available to Gulf through the

Intercompany Interchange Contract’s (IIC) reserve sharing mechanism in times

when Gulf is temporarily short of reserves are key benefits that Gulf and its

customers realize through its association with the SES. In addition, the SES’s

generation organization actively pursues firm energy market products at prices

that can lead to significant savings to the SES and its customers.

Over the next decade, Gulf will face significant challenges in developing a

generation expansion plan that serves not only its customers’ load growth but its

existing base need for capacity. As discussed in the Environmental Concerns

section of this TYSP, compliance with new environmental regulations,

particularily any that may be issued to require lower C02 emissions from power

plants, may lead to accelerated retirements of Gulf‘s existing coal units and the

addition of new gas-fired and nucllear units to replace this capacity. Gulf

continues to monitor the developmerit of state and national policy in the area of

C02 regulation and will consider its options for compliance with the resulting

regulations while still fulfilling its obligation to serve the energy needs of its retail

customers in Northwest Florida with reliable and reasonably priced electricity. If

approved by the FPSC, the addition (of the PPA for 885 MW of gas-fired CC that

Gulf has discussed in this TYSP will meet Gulf‘s future load requirements

71

regardless of which, if any, of the currently proposed state and federal carbon

emission standards ultimately become effective.

72

ENVIRONMENTAL CONCERNS

Gulf will continue to take all necessary actions to fully comply with all

environmental laws and regulations as they apply to the operation of Gulf's

existing generation facilities and the installation of new generation. In the event

that Gulf's recently signed 885 MW PPA does not receive FPSC approval, the

Company's next potential generating unit addition, an 840 megawatt "G" class

combined cycle would be on-line by *June 2014. If needed, this combined cycle

unit will be designed and constructed to comply with all applicable environmental

laws and regulations. Gulf has developed and routinely updates its

environmental compliance strategy to serve as a road map for a reasonable,

least-cost compliance plan. This road map establishes general direction, but

allows for individual decisions to be made based on specific information available

at the time. This approach is an absolute necessity in maintaining the flexibility

to match a dynamic regulatory environment with the variety of available

co m p I ia n ce opt ions .

Gulf updates or reviews its environmental compliance strategy on an

annual basis unless significant events dictate otherwise. The focus of the

strategy updates has, to date, ceintered on compliance with the acid rain

requirements, while considering other significant clean air requirements and

potential new requirements. There are a number of issues associated with future

regulatory requirements that could significantly impact both the scope and cost of

compliance over the next decade. The following is a summary of Gulf's actions

73

taken, or to be taken to comply with each major area of existing and emerging

environmental law and regulations.

Clean Air Act Amendments of 1990

In 1990, Congress passed major revisions to the Clean Air Act requiring

existing coal-fired generating plants to substantially reduce air emissions of sulfur

dioxide (S02) and nitrogen oxides (NOx) by 50 percent by the end of 2000.

Compliance actions for SO2 have included fuel switching to lower sulfur coals

coupled with the use of banked emission allowances and the acquisition of

additional allowances for future year compliance. In addition to reducing SO2

emissions, Gulf has installed low NOx burners on all but two of its coal-fired units

and installed an additional post-combustion NOx control on its largest coal-fired

unit. The Company utilizes a system-wide NOx emissions averaging plan to

meet the requirements of the Act.

Air Quality Standards for Ozone

In 1997, the Environmental Protection Agency (EPA) announced a

stringent new eight hour National Ambient Air Quality Standard (NAAQS) for

ozone based on an eight-hour average. In 2002, Gulf entered into an agreement

with the Florida Department of Environmental Protection (FDEP) to reduce NOx

emissions at Plant Crist in order to help ensure that the new ozone standard is

attained in the Pensacola area. Gulf installed Selective Catalytic Reduction

(SCR) controls on Crist Unit 7 in May 2005. In addition to the SCR control on

Unit 7, the Company installed Selective Non-Catalytic Controls (SNCR) and over-

fire air on Crist Unit 6 in February 2006 and SNCR controls on Crist Unit 4 and

74

Unit 5 in April 2006. These controls have achieved the overall plant-wide NOx

emissions overage of 0.20 Ibs/mmbtu as outlined in the FDEP Agreement. Gulf

also retired Crist Unit 1 in March 2003 and Crist Units 2 and 3 in May 2006.

All Florida counties currently meet the new standard, however in March

2008, the EPA issued new rules lowering the eight hour ozone standard. Based

on data from 2005-2007, counties within Gulf's service area would be designated

non-attainment under the new standard. However, controls that have been

recently installed or that are planned in response to EPA's Clean Air Interstate

Rule may achieve compliance without additional measures. States are required

to recommend designations to EPA by March 2009, and EPA will officially

designate non-attainment areas by March 201 0. States must then submit

revisions to their State Implementation Plans by March 201 3.

Clean Air Interstate Rule

The EPA issued the final Clean Air Interstate Rule in March 2005. This

cap-and-trade rule addresses power plant SO;! and NOx emissions that were

found to contribute to non-attainment of the eight-hour ozone and fine particulate

matter standards in downwind states. Twenty-eight eastern states, including

Florida and Mississippi, are subject to the requirements of the rule. The rule calls

for additional reductions of NOx and/or SO2 to be achieved in two phases,

2009/2010 and 2015, respectively. Compliance with this rule will be

accomplished by the installation of 'additional emission controls at Gulf's coal-

fired facilities and by the purchase of supplemental emission allowances through

a cap-and-trade program.

75

Clean Air Visibility Rule

The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was

finalized in July 2005. The goal of this rule is to restore natural visibility

conditions in certain areas (primarily national parks and wilderness areas) by

2064. The rule involves the application of Best Available Retrofit Technology

(BART) requirements and, beginning in 2018, a review each decade and

implementation of the additional emissions reductions necessary to continue

making reasonable progress toward the goal of natural visibility. BART requires

that certain BART-eligible sources that contribute to visibility impairment

implement additional emission reductions to address these contributions. For

power plants, the Clean Air Visibility Rule allows states to determine that the

Clean Air Interstate Rule satisfies BART requirements for SOs and NOx but not

particulate matter, which requires a separate BART analysis. In addition to

BART controls, additional requirements could be imposed to achieve progress

toward the long-term goal. Florida has submitted a State Implementation Plan

(SIP) to EPA that contains emission reduction strategies for implementing BART

requirements and for achieving sufficient and reasonable progress toward the

goal. If Florida’s SIP is approved by EPA, Gulfs generating facilities will not be

impacted by the early phases of the Clean Air Visibility Rule.

Clean Air Mercury Rule

In March 2005, the EPA announced the final Clean Air Mercury Rule, a cap-and-

trade program for the reduction of mercury emissions from coal-fired power

plants. The rule sets caps on mercury emissions to be implemented in two

76

phases, 201 0 and 201 8, respectively, and provides for an emissions allowance

trading market. Florida submitted state rules intended to implement the Clean Air

Mercury Rule to EPA in December 2006. In February 2008, however, the U.S.

Court of Appeals for the District of Columbia Circuit vacated the federal Clean Air

Mercury Rule. The vacatur became effective with the issuance of the court’s

mandate on March 14, 2008. With CAMR voided, electric generating facilities

are no longer required to install mercuiry controls to meet the CAMR cap and

trade emission limits. Pursuant to the vacatur, EPA is expected to initiate new

mercury rulemaking proceedings to develop Maximum Achievable Control

Technologies (MACT) standards for power plants; however, this process could

take multiple years to complete. Development of new MACT mercury standards

could require substantial capital expenditures or affect the timing of current

budgeted capital expenditures that cannot be determined at this time.

Global Climate Issues

In April 2007, the U.S. Supreme Court ruled that the EPA has authority

under the Clean Air Act to regulate greenhouse gas emissions from new motor

vehicles. The EPA is currently developing its response to this decision.

Regulatory decisions that will follow from this response may have implications for

both new and existing stationary soiirces, such as power plants. The ultimate

outcome of these rulemaking activities cannot be determined at this time;

however, as with the current legislative proposals, mandatory restrictions on the

Company’s greenhouse gas emissions could result in significant additional

compliance costs that could affect future unit retirement and replacement

decisions.

77

On July 13, 2007, the Governor of the State of Florida signed three

executive orders addressing the reduction of greenhouse gas emissions within

the state, including statewide emission reduction targets beginning in 201 7.

Included in the orders is a directive to the Florida Secretary of Environmental

Protection to develop rules adopting maximum allowable emissions levels of

greenhouse gases for electric utilities, consistent with the statewide emission

reduction targets, and a request to the Florida Public Service Commission to

initiate rulemaking requiring utilities to produce at least 20% of their electricity

from renewable sources. The impact of these orders on the Company will

depend on the development, adoption, and implementation of any rules

governing greenhouse gas emissions, and the ultimate outcome cannot be

determined at this time.

Gulf will continue its involvement in the development of strategies to

address any future clean air requirements in order to minimize the uncertainty

related to the scope and cost of compliance. As new clean air initiatives emerge,

Gulf will support any proposal that would help it meet environmental goals and

objectives in a logical and cost effective way, provided that the standards are

based on sound science and economics which allow for adequate time to comply

without compromising the safe, reliable and affordable supply of electricity to

Gulf's customers.

78

AVAILABILITY OF SYSTEM INTERCHANGE

Gulf coordinates its operations with the other operating companies of the

SES: Alabama Power Company, Georgia Power Company, Mississippi Power

Company, and Southern Power Company. In any year, an individual operating

company may have a temporary surplus or deficit in generating capacity,

depending on the relationship of its (generating capacity to its load and reserve

responsibility. Each SES operating company either buys or sells its temporary

deficit or surplus capacity from or .to the pool in order to satisfy its reserve

responsibility requirement. This is accomplished through the reserve sharing

provisions of the SES Intercompany Interchange Contract (IIC) that is reviewed

and updated annually.

OFF-SYSTEM SALES

Gulf and other SES operating companies have negotiated the sale of

capacity and energy to several utilities outside the SES. The terms of the

existing contracts began prior to 2005 and extend into 2010. In addition, three

new contracts have been finalized, and are scheduled to be in effect beginning in

the summer of 2010. Two of the contracts end in December 2015, while the

other contract will end in May 2019. Gulfs share of the capacity and energy

sales is reflected in the reserves on Schedules 7.1 and 7.2 and the energy and

fuel use on Schedules 5 and 6.1.

79

CHAPTER IV

FORECAST OF FACILITIES REQUIREMENTS

CAPACITY RESOURCE ALTERNATIVES

POWER PURCHASES

Gulf's use of purchased power arrangements in previous years has

proven to be a successful approach to meeting its reliability needs. In order to

meet its future need for capacity in 2014 and beyond, longer-term purchased

power from the market will be factored into expansion studies in order to evaluate

its effect on supply flexibility and reduced commitment risk during periods in

which environmental regulations (with considerable economic impacts) and

legislative initiatives focusing on generation additions are in various stages of

development.

Gulf will continue to utilize both short-term and longer-term purchased

power in the future to balance its approach to supply side resource development.

In efforts to further diversify its generation fuel mix, Gulf has developed a RFP for

the supply of capacity and energy froin renewable resources. Gulf issued its first

renewables RFP in 2008, and will be prepared to do so in the future. If future

solicitations ultimately result in proposals that are competitive with resources that

Gulf would otherwise develop, the Company will secure this renewable capacity

and energy through a PPA.

Another avenue for the purchase of renewable energy is through Gulf's

Renewable Standard Offer Contract I(RSOC) that is on file with the FPSC and is

continually available to developers of renewable resources. This contract offers

to purchase renewable capacity and (energy at the Company's avoided cost of its

80

next planned generating unit additions as shown in its current TYSP. Finally, per

FPSC rules related to renewable energy procurement, Gulf may negotiate a PPA

with a renewable energy supplier if the terms and conditions of the RSOC are not

suitable for a particular renewable project.

CAPACITY ADDITIONS

In conjunction with the SES, Gulf will conduct economic evaluations of its

potential supply options in order to determine the most cost-effective means of

meeting its future capacity obligations. Gulf will evaluate its internal construction

options versus external development of capacity resources in order to determine

how to best meet its future capacity obligations. All commercially available

generating technologies such as gas combustion turbine and combined cycle,

conventional pulverized coal, and nuclear will be included in future SES IRP mix

studies. In addition, emerging integrated gasification combined cycle (IGCC)

technologies, such as air blown IGCC, will be added to the future generation mix

studies so that their potential economic and technical viabilities may be

evaluated. While there is only limited operational experience that aids in

approximating the economic and performance characteristics of full-scale air

blown IGCC facilities, the potential benefits of the technology include greater

efficiency and lower environmental emissions.

If subsequent mix studies or RFPs identify alternative power supply

technologies or purchased power options that are more economical or that

deliver more desirable results, Gulf will modify its expansion plan to reflect the

81

proposed procurement of these resources. Gulf will continue to review all

available capacity resource possibilities in order to serve the energy needs of its

retail customers in Northwest Floriida with reliable and reasonably priced

electricity.

82

PREFERRED AND POTENTIAL SITES FOR CAPACITY ADDITIONS

Studies to determine a preferred site for the construction of the 2014 CC

unit identified on Schedule 9 of this TYSP were essentially completed in late Fall

of 2008, showing the Plant Crist site to be a more cost effective location for this

unit over the next best site, Plant Smith. However, the analysis will have to be

revisited to reflect new information related to construction and fuel supplies if

Gulf's 885 MW PPA is not approved by the FPSC. Therefore, given the possible

impacts on conclusion of the site location study due to new information, Gulf is

showing both the Plant Crist site in Escambia County, Florida and the Plant

Smith site in Bay County, Florida as potential sites being considered for locating

Gulf's next planned generating unit in Northwest Florida: Each of these potential

sites has unique characteristics that offer construction and/or operational

advantages related to the potential installation of natural gas-fired CCs. Site

selection for Gulf's next planned generating unit is based on existing

infrastructure, available acreage and land use, transmission, fuel facilities,

environmental factors including evolving ozone standards, and overall project

economics .

The required environmental and land use information for each potential

site is set forth below. The estimated peak water usage for the proposed CC

should be identical for each site mentioned below. Gulf projects that

approximately 5000 gallons per minute (gpm) would be required for industrial

83

cooling water needs, while 250 gpm would be required for domestic, irrigation,

and other potable and non-potable Walter uses.

84

Potential Site #I: Plant Crist, Escambia County

The project site would be located on Gulf's existing Plant Crist property in

Escambia County, Florida. If a future project is ultimately located on this

property, detailed studies must first be completed to determine the exact size and

location of the project site within the plant property's boundaries in order to meet

Gulf's needs while insuring full compliance with local, state, and federal

requirements. The plant property, approximately 10 miles north of Pensacola,

Florida, can be accessed via county roads from nearby U. S. Highway 29. As

shown on Schedule 1, the existing Plant Crist facility consists of 930 MW of

steam generation.

U. S. Geological Survey (USGS) Map

A USGS map showing the general location of the Plant Crist property is

found on page 88 of this chapter.

Land Uses and Environmental Features

The Plant Crist property is dedicated to industrial use. The land adjacent

to the property is currently being used for residential, commercial, and

industrial purposes. General environmental features of the undeveloped

portion of the property include mixed scrub, mixed hardwood/pine forest,

and some open grassy areas. This property is located on the Escambia

River. There are no unique or significant environmental features on the

property that would substantially affect project development.

85

Water Supply Sources

For industrial processing, cooling, and other water needs, Gulf would likely

use a combination of groundwater from on-site wells, available surface

water, and potential reclaimed water sources.

Potential Site #2: Plant Smith, Bay County

The project site would be located on Gulf's existing Plant Smith property in

Bay County, Florida. If a future project is ultimately located on this property,

detailed studies must first be completed to determine the exact size and location

of the project site within the plant property's boundaries in order to meet Gulf's

needs while insuring full compliance with local, state, and federal requirements.

The plant property, approximately 10 miles northwest of Panama City, Florida, is

located on North Bay and can be accessed via a county road from nearby State

Road 77. As shown on Schedule 1, the existing Plant Smith facility consists of

357 MW of steam generation, 556 IWW of combined cycle generation, and 32

MW of CT generation.

U. S. Geological Survev (USGS) Map

A USGS map showing the general location of the Plant Smith property is

found on page 89 of this chapter.

Land Uses and Environmental Features

The Plant Smith property is dedicated to industrial use. The land adjacent

to the property is rural and consists of planted pine plantations. General

environmental features of the property include a mixture of upland and

86

wetland areas. This property is located on North Bay, which connects to

St. Andrews Bay. The property has no unique or significant environmental

features that would substantially affect project development.

Water Supply Sources

For industrial processing, cooling, and other water needs, Gulf would likely

use a combination of groundwater from on-site wells and available surface

water.

87

' . ,

. . - , I '

' I

- . . . . . . .

! '

88

- Notes. 1 Grid lines shown ore based on the Florida North Zone (#903),

NAD83-90 H A R N State Plane Coordinate System

2 raken from U S G S Quadrangle Maps "Pace,FI and Cantmnent , AIOVIIII.II-

ONE ENERGY PLACE FI "

1000 0 1000 2000 - SCALE: 1 INCH = 2000 FEET

89

GULF POWER COMPANY

SCHEDULE 7.1 FORECAST OF CAPACITY, DEMAND, AND SCHEDULED MAINTENANCE AT TIME OF SUMMER PEAK (A)

(4) (5) (6) (7)

FIRM TOTAL FIR!

RES E RVE MARGIN BEFORE

MAINTENANCE INSTALLED CAPACITY CAPACITY CAPACITY PEAK SCHEDULED CAPACITY IMPORT EXPORT NUG AVAILABLE DEMAND % MAINTENANCE

YEAR MW (6) MW MW MW MW MW OF PEAK MW MW - 2009 201 0 201 1 2012

2014 \o 0 201 5

2016 201 7 201 8

-n..Y LU Id

2.703 2,673 2.671 2.566

2.648 2.638 2.638 2.638 2,606

c) cco L.UdU

488 48% 488 488

885 885 885 885 885

A Q Q TU"

0 0 0 0 c! 0 0 0 0 0

2,980 2,950 2,948 2,843 - 7,awi I--

3,322 3,312 3,312 3,312 3,280

2 608 372 2.670 280 2 754 194 2.794 49 2 857 78 2 917 405 2 979 333 3.026 286 3 107 205 3 196 84

14.3% NONE 10.5% 7.0% 1.8% 2.7%

13.9% 11.2% 9.5% 6.6% 2.6%

RES E RVE MARGIN AFTER MAINTENANCE

Y O

MW OF PEAK

372 14.3% 280 10.5% 194 7.0% 49 1.8% 78 2.7%

405 13.9% 333 11.2% 286 9.5% 205 6.6%

84 2.6%

NOTE: (A) CAPACITY ALLOCATIONS AND CHANGES MUST BE MADE BY JUNE 30 TO BE CONSIDERED IN EFFECT AT THE TIME OF THE SUMMER PEAK. ALL VALUES ARE SUMMER NET MW.

(8) 840 MW CC SHOWN ON SCHEDULE 9 FOR 2014 IN-SERVICE REPLACED BY 885 MW PPA SHOWN IN COLUMN (3).

GULF POWER COMPANY

SCHEDULE 7.2 FORECAST OF CAPACITY, DEMAND, AND SCHEDULED MAINTENANCE AT TIME OF WINTER PEAK

(2) (3) (4) (5) (6) (7) (8) (9) (1 0)

RES E RVE MARGIN BEFORE

TOTAL FIRM FIRM TOTAL FIRM MAINTENANCE INSTALLED CAPACITY CAPACITY CAPACITY PEAK SCHEDULED CAPACITY IMPORT EXPORT NUG AVAILABLE DEMAND % MAINTENANCE

YEAR MW (A) MW MW MW MW MW MW OF PEAK MW

2008-09 2,750 0 (211) 0 2,539 2,320 219 9.4% NONE 2009-1 0 2,742 488 (211) 0 3,019 2,399 620 25.8% 2010-1 1 2,712 488 (211) 0 2,989 2,479 510 20.6% 2011-12 2,618 488 (21 11 0 2,895 2,545 350 13.8% 201 2-1 3 2,605 488 (211) 0 2,882 2,611 271 10.4%

2014-15 2,687 885 (211) 0 3,361 2,694 667 24.8%

2016-17 2,677 885 (211) 0 3,351 2,840 511 18.0% 201 7-1 8 2,637 885 (211) 0 3,311 2,911 400 13.7%

2013-14 2,697 488 (211) 0 2,974 2,654 320 12.1%

2015-16 2,677 885 (211) 0 3,351 2,758 593 21.5%

NOTE: (A) 840 MW CC SHOWN ON SCHEDULE 9 FOR 2014 IN-SERVICE REPLACED BY 885 MW PPA SHOWN IN COLUMN (3).

(11) (1 2)

RESERVE MARGIN AFTER MAINTENANCE

% MW OF PEAK

219 9.4% 620 25.8% 510 20.6% 350 13.8% 271 10.4% 320 12.1% 667 24.8% 593 21.5% 51 1 18.0% 400 13.7%

GULF POWER COMPANY

SCHEDULE a PLANNED AND PROSPECTIVE GENERATING FACILITY ADDITIONS AND CHANGES

Page ! of2

(3) (4) (9)

Fuel Const Com'l In- Expected Gen Max Net Capability Unit Unit Fuel Transport Start Service Retirement Nameplate Summer Winter

Plant Name No. Location Type Pri &It - Pri !lJ MoNr MoNr MoNr KW - MW MW Status

Daniel 1 Jackson Cnty, MS 4215Sl6W

FS C HO RR TK 09/77 06/09 274,125 (7.0) (7.0) CR

Scherer

Crist

Crist

Crist

Crist

Monroe Cnty, GA FS

FS

FS

FS

FS

c --

C NG

C NG

C NG

C NG

RR --

WA PL

WA PL

WA PL

WA PL

1 I87

7/59

616 1

05/70

08173

06/09

06/10

06/10

0611 0

0611 0

222,750

93,750

93,750

369,750

578,000

3,000

(1.0) (1.0)

(5.0) (5.0)

(5.0) (5.0)

(6.0) (6.0)

(17.0) (17.0)

3 0 3.0


Escambia County 25/1 N130W


Escambia County 2511 N/30W

Perdido 1 - 2 IC LFG -- PL -- 04/09 0411 0 12/29 P Escambia County

Scherer 3 Monroe Cnty, GA __

FS c -- RR -- 1/87 0611 1 222,750 (2.0) (2.0) D

Scholz 1 Jackson Cnty, FL 12/3N17W

FS c -- RR WA 03/53 12/11 49,000 (46.0) (46.0) R

Scholz 2 Jackson Cnty, FL 1213N17W

FS c -- RR WA 10153 1211 1 49,000 (46.0) (46.0) R

GULF POWER COMPANY

SCHEDULE 8 PLANNED AND PROSPECTIVE GENERATING FACILITY ADDITIONS AND CHANGES

Page 2 of 2

(3) (4) (5)

Fuel Const Com'l In- Expected Gen Max Net Capability Unit Unit Fuel Transport Start Service Retirement Nameplate Summer Winter

MW MW Status MoNr KW - Plant Name No. Location Type Pri @ - Pri - Alt MoNr MoNr

Crist 6 EscambiaCounty FS C NG WA PL _ _ 05/70 0611 2 369,750 (13.0) (13.0) D 2511 N130W

Scholz S WDS -- TK RR 01/12 06/13 12/42 49,000 46.0 46.0 P 1 Jackson Cnty, FL 12/3N/7W

Scholz 2 Jackson Cnty, FL 12/3N17W

S WDS -- TK RR 01/12 06/13 12/42 49,000 46.0 46.0 P

Daniel

Daniel

Daniel

Daniel

Smith

1 Jackson Cnty, MS 42/5S/6W

FS

FS

FS

FS

CT

C HO

C HO

C HO

C HO

LO --

RR TK

RR TK

RR TK

RR TK

TK --

_ _ 09/77

_- 0618 1

_ _ 09/77

__ 06/81

_ _ 05/71

06/14

0611 4

0611 5

0611 5

1211 7

274,125 (5.0) (5.0) D


274,125

274,125

274,125

41.850

(5.0) (5.0)

(5.0) (5.0)

(5.0) (5.0)

(32.0) (40.0)


2 Jackson Cnty, MS 4215S16W

A Bay County, FL 36/2S/15W

Abbreviations: - Fuel Unit TvDe Fuel TransDortation

FS - Fossil Steam

CT - Combustion Turbine CC - Combined Cycle IC - Internal Combustion

S - Steam C - Coal

NG - Natural Gas LO - Light Oil HO - Heavy Oil LFG - Landfill Gas WDS -Wood Waste Solid

CR - Certified Rating change D - Environmental derate P - Planned, but not authorized by utility R - To be retired V - Under construction, more than 50% complete

PL - Pipeline TK - Truck RR - Railroad WA - Water

Gulf Power Company Page 1 of 1

Schedule 9 Status Report and Specifications of Proposed Generating Facilities

(i j Piani Name and tinit Number:

(2) Net Capacity a. Summer: b. Winter

Gross Capacity a. Summer: b. Winter

(3) Technology Type:

(4) Anticipated Construction Timing a. Field construction start - date: b. Commercial in-service date:

(5) Fuel a. Primary fuel: b. Alternate fuel:

(6) Air Pollution Control Strategy:

(7) Cooling Method:

(8) Total Site Area:

(9) Construction Status:

( I O ) Certification Status:

(11) Status with Federal Agencies:

(12) Projected Unit Performance Data Planned Outage Factor (POF): Unplanned Outage Factor (UOF): Equivalent Availability Factor (EAF): Capacity Factor (%): Average Net Operating Heat Rate (ANOHR):

(13) Projected Unit Financial Data (A)

Book Life (Years): Total Installed Cost (In-Service Year $IkW):

Direct Construction Cost ('09 $IkW): AFUDC Amount ('14 $/kW): Escalation ($/kW):

Fixed O&M ('14 $/kW - Yr): Variable 0&M ('14 $IMWH): K Factor:

iinknown

840 MW 900 MW

850 MW 910 MW

High Output "G" Combined Cycle

1011 1 0611 4

Natural Gas NIA

Dry low NOx combustor for natural gas SCR

Evaporative cooling

Unknown

(A) Fixed O&M without firm gas transportation cost

This facility is proposed but not authorized by Utility

Not applied

Not applied

5.8% 5.5%

88.7% 65.0% 6,874

40 1132 873 171 88

8.1 1 1.71

1.4092

C 0 cn cn .- .- 5 C E l-

W C m t: 0 Q

2

C

2 C Y C 3

W C 0 C cn .- .- 6 Y- 0 * C 0 .- a h

7 v

C C C C

C C C 0 0 0 C C C C Y Y Y Y Y Y Y C C C C C C K S

3 3 3

3 3 3 3 3 3 3 2

Y- O 5 E z

a 3

h

CL

g ul C a, J a, C A .- h

2L

bj cn m CI - P

5

95

=r - psc.state.fl.us

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